81_FR_25
Page Range | 6411-6743 | |
FR Document |
Page and Subject | |
---|---|
81 FR 6562 - Sunshine Act Meeting | |
81 FR 6430 - Elimination of Nonimmigrant Visa Exemption for Certain Caribbean Residents Coming to the United States as H-2A Agricultural Workers | |
81 FR 6571 - 60-Day Notice of Proposed Information Collection: Overseas Schools Grant Status Report | |
81 FR 6501 - Secretary's Advisory Committee on Animal Health; Meeting | |
81 FR 6477 - Oklahoma Regulatory Program | |
81 FR 6504 - Information Collection Activity; Comment Request | |
81 FR 6479 - Virginia Regulatory Program | |
81 FR 6518 - Commission To Eliminate Child Abuse and Neglect Fatalities; Announcement of Meetings | |
81 FR 6518 - Submission for OMB Review; Permits, Authorities, or Franchises | |
81 FR 6516 - Information Collection; Use of Project Labor Agreements for Federal Construction Projects | |
81 FR 6537 - North Cumberland Wildlife Management Area, Tennessee Lands Unsuitable for Mining Draft Petition Evaluation Document and Environmental Impact Statement-OSM-EIS-37 | |
81 FR 6519 - Submission for OMB Review; Evaluation of Export Offers | |
81 FR 6524 - Office of Foods and Veterinary Medicine; Center for Food Safety and Applied Nutrition; Statement of Organization, Functions, and Delegations of Authority | |
81 FR 6503 - Idaho Panhandle Resource Advisory Committee; Meeting | |
81 FR 6541 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Department of Labor Generic Solution for “Touch-Base” Activities | |
81 FR 6543 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Self-Employment Training Demonstration Evaluation | |
81 FR 6542 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Petitions for Modification of Mandatory Safety Standards | |
81 FR 6504 - Pure Magnesium From the People's Republic of China: Preliminary Results of Antidumping Duty Administrative Review; 2014-2015 | |
81 FR 6542 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Short-Time Compensation Grants | |
81 FR 6489 - Trade Monitoring Procedures for Fishery Products; International Trade in Seafood; Permit Requirements for Importers and Exporters; Public Meeting | |
81 FR 6458 - Notification and Reporting of Aircraft Accidents or Incidents and Overdue Aircraft, and Preservation of Aircraft Wreckage, Mail, Cargo, and Records | |
81 FR 6511 - Receipt of Test Data Under the Toxic Substances Control Act | |
81 FR 6532 - Agency Information Collection Activities: Collection of Qualitative Feedback Through Focus Groups; Extension, Without Change, of a Currently Approved Collection | |
81 FR 6515 - Information Collection; Central Contractor Registration | |
81 FR 6514 - Information Collection; Taxpayer Identification Number Information | |
81 FR 6517 - Information Collection; Accident Prevention Plans and Recordkeeping | |
81 FR 6453 - Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products: Nasal Decongestant Inhaler/Vapor Inhaler | |
81 FR 6451 - Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products: Vicks® VapoInhaler® | |
81 FR 6526 - Quarterly IRS Interest Rates Used in Calculating Interest on Overdue Accounts and Refunds on Customs Duties | |
81 FR 6528 - Agency Information Collection Activities: Country of Origin Marking Requirements for Containers or Holders | |
81 FR 6528 - Approval of SGS North America, Inc., as a Commercial Gauger | |
81 FR 6529 - Approval of SGS North America, Inc., as a Commercial Gauger | |
81 FR 6525 - Agency Information Collection Activities: Application for Exportation of Articles Under Special Bond | |
81 FR 6506 - Supercalendered Paper From Canada: Initiation of Expedited Review of the Countervailing Duty Order | |
81 FR 6488 - Defense Federal Acquisition Regulation Supplement: DFARS Case 2016-D017, Independent Research and Development Expenses | |
81 FR 6520 - Proposed Revised Vaccine Information Materials for Hepatitis A and Hepatitis B Vaccines | |
81 FR 6460 - Fisheries of the Exclusive Economic Zone Off Alaska; Pacific Cod by Catcher/Processors Using Trawl Gear in the Western Regulatory Area of the Gulf of Alaska | |
81 FR 6507 - Fisheries of the U.S. Caribbean; Southeast Data, Assessment and Review (SEDAR); U.S. Caribbean Data-Limited Species | |
81 FR 6459 - Fisheries of the Exclusive Economic Zone Off Alaska; Directed Fishing With Trawl Gear by Fisheries Act Catcher Processors in Bycatch Limitation Zone 1 of the Bering Sea and Aleutian Islands Management Area | |
81 FR 6533 - 60-Day Notice of Proposed Information Collection: Eligibility of a Nonprofit Corporation/Housing Consultant Certification | |
81 FR 6535 - 60-Day Notice of Proposed Information Collection: Validating Estimates of CPD Grantee Accrued Expenses | |
81 FR 6508 - Marine Mammals; File No. 18537 | |
81 FR 6509 - Marine Mammals; File Nos. 16193 and 17157 | |
81 FR 6534 - Final Fair Market Rents for the Housing Choice Voucher Program and Moderate Rehabilitation Single Room Occupancy Program Fiscal Year 2016; Revised | |
81 FR 6551 - Advisory Committee on the Medical Uses of Isotopes: Meeting Notice | |
81 FR 6549 - Portland General Electric Company; Trojan Independent Spent Fuel Storage Installation in Columbia County, Oregon | |
81 FR 6545 - Comanche Peak Nuclear Power Plant, Units 1 and 2, and Independent Spent Fuel Storage Installation Consideration of Approval of Transfer of Licenses and Conforming Amendments | |
81 FR 6597 - Unblocking of Specially Designated Nationals and Blocked Persons Pursuant to the Foreign Narcotics Kingpin Designation Act | |
81 FR 6539 - Agency Information Collection Activities; Proposed eCollection eComments Requested; Reinstatement, With Change, of a Previously Approved Collection for Which Approval Has Expired: 2016 Law Enforcement Administrative and Management Statistics (LEMAS) Survey | |
81 FR 6540 - Agency Information Collection Activities; Proposed eCollection eComments Requested; Extension With Change, of a Previously Approved Collection Federal Firearms Licensee (FFL) Enrollment/National Instant Criminal Background Check System (NICS) E-Check Enrollment Form, Federal Firearms Licensee (FFL) Officer/Employee Acknowledgement of Responsibilities Under the NICS Form | |
81 FR 6514 - Notice of Proposals To Engage in or To Acquire Companies Engaged in Permissible Nonbanking Activities | |
81 FR 6509 - Technology Advisory Committee Meeting Notice | |
81 FR 6514 - Formations of, Acquisitions by, and Mergers of Bank Holding Companies | |
81 FR 6514 - Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company | |
81 FR 6585 - Notice of Funds Availability Inviting Applications for the Fiscal Year (FY) 2016 Funding Round of the Capital Magnet Fund | |
81 FR 6598 - Sanctions Action Pursuant to Executive Order 13712 | |
81 FR 6584 - Agency Requests for Renewal of a Previously Approved Information Collection: Small Business Transportation Resource Center (SBTRC) Regional Field Offices Intake Form (DOT F 4500) | |
81 FR 6578 - Notice of Funding Availability for the Small Business Transportation Resource Center Program | |
81 FR 6576 - Qualification of Drivers; Exemption Applications; Vision | |
81 FR 6573 - Qualification of Drivers; Exemption Applications; Vision | |
81 FR 6544 - Notice of Intent To Seek Approval To Establish an Information Collection | |
81 FR 6596 - Unblocking of Specially Designated Nationals and Blocked Persons Pursuant to Executive Order 13288, as Amended by Executive Order 13391, and Executive Order 13469 | |
81 FR 6503 - Annual List of Newspapers to be used by the Alaska Region for Publication of Legal Notices of Proposed Projects and Activities Implementing Land and Resource Management Plans, Including Hazardous Fuel Reduction Projects, Subject to the Pre-Decisional Administrative Review Process | |
81 FR 6510 - Notice of Availability: CPSC's Draft 2016-2020 Strategic Plan | |
81 FR 6510 - Agency Information Collection Activities OMB Responses | |
81 FR 6521 - Submission for OMB Review; Comment Request | |
81 FR 6531 - Gratuitous Services Agreement and Volunteer Release and Hold Harmless | |
81 FR 6530 - Infrastructure Assessments and Training | |
81 FR 6529 - Technical Resource for Incident Prevention (TRIPwire) User Registration | |
81 FR 6568 - Agency Information Collection Activities: Proposed Request and Comment Request | |
81 FR 6536 - Information Collection Request Sent to the Office of Management and Budget (OMB) for Approval; UCAN Survey-National Initiative To Understand and Connect Americans and Nature | |
81 FR 6479 - Prescriptions in Alaska and U.S. Territories and Possessions | |
81 FR 6537 - Proposed Appointment to the National Indian Gaming Commission | |
81 FR 6523 - Agency Information Collection Activities; Proposed Collection; Comment Request; Extension for a Currently Approved Collection, State Plan for Independent Living (SPIL) | |
81 FR 6572 - Petition for Exemption; Summary of Petition Received; Wes Myers | |
81 FR 6572 - Petition for Exemption; Summary of Petition Received; Firestorm UAV | |
81 FR 6538 - Potassium Permanganate From China | |
81 FR 6532 - Extension of Agency Information Collection Activity Under OMB Review: Certified Cargo Screening Program | |
81 FR 6551 - Proposed Collection; Comment Request | |
81 FR 6565 - Proposed Collection; Comment Request | |
81 FR 6554 - Proposed Collection; Comment Request | |
81 FR 6552 - Self-Regulatory Organizations; EDGX Exchange, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change to Rule 21.1, Definitions, Relating to the Operation of the Attribution Feature of EDGX Options | |
81 FR 6556 - Self-Regulatory Organizations; Miami International Securities Exchange LLC; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend Exchange Rule 301 | |
81 FR 6562 - Self-Regulatory Organizations; Miami International Securities Exchange LLC; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend Exchange Rules 503 and 515 | |
81 FR 6558 - Self-Regulatory Organizations; BATS Exchange, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Extend the Pilot Period for the Exchange's Supplemental Competitive Liquidity Provider Program | |
81 FR 6560 - Self-Regulatory Organizations; NASDAQ OMX PHLX LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Options Regulatory Fee | |
81 FR 6555 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change to Extend the Implementation Date of the “No-Remuneration” Indicator | |
81 FR 6566 - Self-Regulatory Organizations; NYSE MKT LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change Amending Certain of Its Rules Related to Binary Return Derivatives Contracts | |
81 FR 6512 - Information Collection Being Submitted for Review and Approval to the Office of Management and Budget | |
81 FR 6513 - Information Collection Being Reviewed by the Federal Communications Commission | |
81 FR 6501 - Notice of Request To Renew an Approved Information Collection; Importation and Transportation of Meat, Poultry, and Egg Products | |
81 FR 6595 - Agency Information Collection Activities: Information Collection Renewal; Comment Request; Privacy of Consumer Financial Information | |
81 FR 6512 - Disability Advisory Committee; Announcement of Next Meeting | |
81 FR 6535 - 60-Day Notice of Proposed Information Collection: Screening and Eviction for Drug Abuse and Other Criminal Activity | |
81 FR 6489 - Fisheries of the Exclusive Economic Zone Off Alaska; Western Alaska Community Development Quota Program | |
81 FR 6524 - National Institute on Deafness and Other Communication; Disorders Notice of Closed Meeting | |
81 FR 6525 - National Institute of Diabetes and Digestive and Kidney Diseases; Notice of Closed Meetings | |
81 FR 6525 - National Heart, Lung, And Blood Institute; Notice of Closed Meeting | |
81 FR 6525 - National Library of Medicine; Amended Notice of Meeting | |
81 FR 6481 - Approval of California Air Plan Revisions, Department of Pesticide Regulations | |
81 FR 6598 - Quarterly Publication of Individuals, Who Have Chosen To Expatriate, as Required by Section 6039G | |
81 FR 6483 - Approval and Promulgation of Air Quality Implementation Plans; Texas; Infrastructure or Requirements for the 2008 Ozone and 2010 Nitrogen Dioxide National Ambient Air Quality Standards | |
81 FR 6522 - Proposed Information Collection Activity; Comment Request | |
81 FR 6538 - Notice of Receipt of Complaint; Solicitation of Comments Relating to the Public Interest | |
81 FR 6613 - Agency Information Collection (Evaluation of the Department of Veterans Affairs Mental Health Services); Activities Under OMB Review | |
81 FR 6508 - Mid-Atlantic Fishery Management Council (MAFMC); Public Meeting | |
81 FR 6447 - Amendment of Class E Airspace for the Following Michigan Towns: Alpena, MI; and Muskegon, MI | |
81 FR 6450 - Amendment of Class E Airspace; Wilmington, OH | |
81 FR 6448 - Amendment of Class E Airspace for the Following Minnesota Towns: Rochester, MN; and St. Cloud, MN | |
81 FR 6454 - Federal Motor Vehicle Safety Standards; Lamps, Reflective Devices, and Associated Equipment | |
81 FR 6411 - Competitive and Noncompetitive Non-Formula Federal Assistance Programs-General Award Administrative Provisions and Specific Administrative Provisions | |
81 FR 6475 - Airworthiness Directives; The Boeing Company Airplanes | |
81 FR 6434 - Capital Magnet Fund | |
81 FR 6469 - Personnel Management in Agencies | |
81 FR 6462 - Financial Assistance Interior Regulation | |
81 FR 6418 - Single Family Housing Guaranteed Loan Program | |
81 FR 6687 - Additions to List of Categorical Non-Waste Fuels | |
81 FR 6615 - Waste Prevention, Production Subject to Royalties, and Resource Conservation |
Animal and Plant Health Inspection Service
Food Safety and Inspection Service
Forest Service
National Institute of Food and Agriculture
Rural Housing Service
Rural Utilities Service
International Trade Administration
National Oceanic and Atmospheric Administration
Defense Acquisition Regulations System
Centers for Disease Control and Prevention
Children and Families Administration
Community Living Administration
Food and Drug Administration
National Institutes of Health
Transportation Security Administration
U.S. Citizenship and Immigration Services
U.S. Customs and Border Protection
Fish and Wildlife Service
Land Management Bureau
Surface Mining Reclamation and Enforcement Office
Drug Enforcement Administration
Federal Aviation Administration
Federal Motor Carrier Safety Administration
National Highway Traffic Safety Administration
Community Development Financial Institutions Fund
Comptroller of the Currency
Foreign Assets Control Office
Internal Revenue Service
Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, and notice of recently enacted public laws.
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National Institute of Food and Agriculture, USDA.
Final rule.
The National Institute of Food and Agriculture (NIFA) is publishing as a final rule, a set of general and specific administrative requirements applicable to competitive and non-competitive non-formula programs. The purpose of this final rule is to implement sections of the Agriculture Act of 2014 making it necessary to modify the general administrative provisions as well as specific grant programs. The purpose of the final rule also is to adopt as final interim administrative provisions. Although this final rule becomes effective on the date of publication, NIFA is requesting comments for a 60-day period. See the
This final rule becomes effective on February 8, 2016.
You may submit comments by any of the following methods:
1. Federal eRulemaking Portal:
2.
3.
4.
5.
Maria Koszalka, Division Director, Policy and Oversight Division, Phone: 202-401-4325, Email:
This rulemaking is authorized by section 1470 of the National Agricultural Research, Extension, and Teaching Policy Act of 1977 (NARETPA), as amended,
A primary function of NIFA is the fair, effective, and efficient administration of Federal assistance programs implementing agricultural research, education, and extension programs. The awards made under the above authority are subject to the NIFA assistance regulations at 7 CFR part 3430, Competitive and Noncompetitive Non-formula Federal Assistance Programs—General Award Administrative Provisions. NIFA's development and publication of this regulation for its non-formula Federal assistance programs serve to enhance its accountability and to standardize procedures across the Federal assistance programs it administers while providing transparency to the public. NIFA published 7 CFR part 3430 with subparts A through F as a final rule on September 4, 2009 (74 FR 45736-45752). These regulations apply to all Federal assistance programs administered by NIFA except for the formula grant programs identified in 7 CFR 3430.1(f), the Small Business Innovation Research programs with implementing regulations at 7 CFR part 3403, and the Veterinary Medicine Loan Repayment Program (VMLRP), with implementing regulations at 7 CFR part 3431.
NIFA organized the regulation as follows: Subparts A through E provide administrative provisions for all competitive and noncompetitive non-formula Federal assistance programs. Subparts F and thereafter apply to specific NIFA programs.
NIFA is, to the extent practical, using the following subpart template for each program authority: (1) Applicability of regulations, (2) purpose, (3) definitions (those in addition to or different from § 3430.2), (4) eligibility, (5) project types and priorities, (6) funding restrictions, (7) matching requirements, and (8) duration of grant. Subparts F and thereafter contain the above seven components in this order. Additional sections may be added for a specific program if there are additional requirements or a need for additional rules for the program (
Through this rulemaking, NIFA is making minor additions to Subparts A—General Information, B—Pre-award: Solicitation and Application, and E—Post-Award and Closeout of the administrative provisions in order to meet the new matching requirements and the application process for Non-Land-Grant College of Agriculture designation identified in the Agriculture Act of 2014 (Pub. L. 113-79 or the 2014 Farm Bill). In addition, sections of the 2014 Farm Bill make it necessary to modify administrative provisions for specific grant programs located in Subparts F, G, H, J and O. The rulemaking also will serve to finalize the administrative provisions located in Subpart I and to add a new Subpart L. Further details of these program-specific subparts are as follows.
Subpart F contains the administrative provisions for the Specialty Crop Research Initiative (SCRI). The purpose of SCRI is to address the critical needs of the specialty crop industry by developing and disseminating science-based tools to address needs of specific crops and their regions. Specialty crops are defined as fruits and vegetables, tree nuts, dried fruits, and horticulture and nursery crops (including floriculture).
Subpart G contains the administrative provisions for the Agriculture and Food Research Initiative (AFRI). The purpose of AFRI is to make competitive grants for fundamental and applied research, extension, and education to address food and agricultural sciences, as defined under section 1404 of the National Agriculture Research, Extension, and Teaching Policy Act of 1977 (7 U.S.C. 3103).
Subpart H contains the administrative provisions for the Organic Agriculture Research and Extension Initiative OREI) program. The OREI program is a competitive grant program that supports research and extension activities regarding organically grown and processed agricultural commodities in accordance with congressionally determined purposes. This program funds projects that will enhance the ability of producers and processors who have already adopted organic standards to grow and market high quality organic agricultural products. Priority concerns include biological, physical, and social sciences, including economics.
Subpart I contains the administrative provisions for the Integrated Research, Education, and Extension Competitive Grants (406) Program. The 406 program provides funding for integrated, multifunctional agricultural research, extension, and education activities.
Subpart J contains the administrative provisions for the Beginning Farmer and Rancher Development Program (BFRDP). BFRDP is a beginning farmer and rancher development program that provides local and regional training, education, outreach, mentoring and technical assistance initiatives for individuals who have not operated a farm or ranch, or have operated a farm or ranch for less than ten years. Grants are awarded on a competitive basis in accordance with legislatively determined focus areas.
Administrative provisions for the Capacity Building Grants for Non-Land Grant Colleges of Agriculture Program (NLGCA) are being added to Subpart L. NLGCA is a competitive program to assist the NLGCA Institutions in maintaining and expanding the capacity to conduct education, research, and outreach activities relating to agriculture, renewable resources, and other similar disciplines.
The administrative provisions for the Sun Grant Program are in Subpart O. The purpose of the Sun Grant Program is to provide a consortium of universities with a grant to support a North-Central, Southeastern, South-Central, Western, and Northeastern Sun Grant Center and a Western Insular Pacific Subcenter for the purpose of enhancing national energy security through the development, distribution, and implementation of biobased energy technologies; promoting diversification in, and the environmental sustainability of, agricultural production in the United States through biobased energy and product technologies; promoting economic diversification in rural areas of the United States through biobased energy and product technologies; and enhancing the efficiency of bioenergy and biomass research and development programs through improved coordination and collaboration among the Department of Agriculture, other appropriate Federal agencies (as determined by the Secretary), and Land Grant Institutions.
Section 7301 of the 2014 Farm Bill amended section 103(a)(2) of the Agricultural Research, Extension, and
Education Reform Act of 1998 (7 U.S.C. 7613(a)(2)) by adding relevance as part of merit review and extended the review to include agricultural research grants. Given the 7 CFR part 3430 definitions of merit review and scientific peer review already include relevance and encompass research, modifications to the administrative provisions for these 2014 Farm Bill items are not planned; however, input is welcomed.
Matching—Currently, 7 CFR 3430.52, identifies that “the required percentage of matching, type of matching (
Non-Land-Grant Designation—Since the non-land-grant designation affects an institution's eligibility for some NIFA funding, the plan is to modify § 3430.16, eligibility requirements, to identify the process to request NIFA's consideration (
Merit Review—The 2014 Farm Bill also addresses merit review. Specifically, it adds “relevance” of research projects as part of their merit review, includes “research,” and increases the involvement of the Advisory Board. Given the definitions of merit review and scientific peer review already include relevance and encompass research, modifications to 7 CFR part 3430 for these 2014 Farm Bill items are not planned, but rather, will be addressed in the preamble instead of the final rule.
Section 7306 of the 2014 Farm Bill introduced changes to the Specialty Crop Research Initiative that require administrative revisions to the regulation governing the program.
Section 7404 of the 2014 Farm Bill amended the priority areas for the AFRI program making it necessary to modify the program's administrative provisions.
As a result of the Food, Conservation, and Energy Act of 2008 (2008 Farm Bill), NIFA published an interim final rule on September 9, 2010 (75 FR 54759). In response to the interim final rule, OREI received one comment from a professional organization, the Organic Farming Research Foundation (OFRF), who objected to the purpose and definition of Subpart H—OREI (7 U.S.C. 5925b) and recommended that the purpose and definitions be expanded to include education components. We note, that in regards to OFRF's recommendation to modify the “purpose” and “definition” to include education components, Section 7211 of the 2014 Farm Bill has generated the necessary change to accommodate the OFRF comment recommendation and NIFA will be making changes consistent with the comment and the 2014 Farm Bill. Additionally, through this final rule, NIFA will finalize the Subpart H portion of the interim final rule published on September 9, 2010 and will make the changes necessitated by the 2014 Farm Bill.
On September 9, 2010 (75 FR 54759) NIFA published an interim rule where NIFA proposed adding three subparts
Section 7409 of the 2014 Farm Bill introduced changes to the BFRDP to, for example, address new priorities and broaden the community of potential beneficiaries. These changes require administrative revisions to the regulation. These regulations apply to all recipients of Federal funds under the BFRDP. The proposed changes are intended to provide clear, transparent, and consistent guidance to stakeholders and potential applicants and recipients. For instance, the 2014 Farm Bill added emphasis for projects serving military veterans who wish to begin a career in agriculture, updated the focus areas that funded programs and services will address, and expanded the class of entities with experience in new agricultural producer training and outreach to which NIFA will give priority.
Section 7138 of the 2008 Farm Bill established the NLGCA program. Administrative provisions have not yet been established for the program. NIFA will establish administrative provisions in Subpart L for the program following the subpart template which, at a minimum, is to include: (1) Applicability of regulations, (2) purpose, (3) definitions (those in addition to or different from § 3430.2), (4) eligibility, (5) project types and priorities, (6) funding restrictions (including indirect costs), and (7) matching requirements.
Section 7516 of the 2014 Farm Bill introduced changes to the Sun Grant Program that require administrative revisions to the regulation governing the program.
This rule concerns matters relating to `grants, benefits, or contracts,' 5 U.S.C. 553(a)(2), and is therefore exempt from the requirement of prior notice and comment.
This action has been determined to be not significant for purposes of Executive Order 12866.
This final rule has been reviewed in accordance with the Regulatory Flexibility Act of 1980, as amended by the Small Business Regulatory Enforcement Fairness Act of 1996, (5 U.S.C. 601-612). The Department certifies that this final regulation will not have a significant economic impact on a substantial number of small entities. This final regulation will affect institutions of higher education receiving Federal funds under this program. The U.S. Small Business Administration Size Standards define institutions as “small entities” if they are for-profit or nonprofit institutions with total annual revenue below $5,000,000 or if they are institutions controlled by governmental entities with populations below 50,000. The rule does not involve regulatory and informational requirements regarding businesses, organizations, and governmental jurisdictions subject to regulation.
The Department certifies that this final rule has been assessed in accordance with the requirements of the Paperwork Reduction Act, 44 U.S.C. 3501
This final regulation applies to the following Federal financial assistance programs administered by NIFA including CFDA No. 10.309, Specialty Crop Research Initiative; CFDA No. 10.307, Organic Agriculture Research and Extension Initiative; CFDA No. 10.303, Integrated Research, Education, and Extension Competitive Grants Program; CFDA No. 10.310, Agriculture and Food Research Initiative (AFRI); CFDA No. 10.311, Beginning Farmer and Rancher Development Program; CFDA No. 10.326, Capacity Building for Non-Land Grant Colleges of Agriculture; and CFDA No. 10.320, Sun Grant Program.
The Department has reviewed this final rule in accordance with the requirements of Executive Order No. 13132 and the Unfunded Mandates Reform Act of 1995, 2 U.S.C. 1501
Executive Order 12866 and the President's Memorandum of June 1, 1998, require each agency to write all rules in plain language. The Department invites comments on how to make this final rule easier to understand.
Administrative practice and procedure, Agricultural research, Education, Extension, Federal assistance.
Accordingly, the Department of Agriculture, National Institute of Food and Agriculture, adopts the interim rule amending 7 CFR part 3430 which was published at 75 FR 54759 on September 9, 2010, as a final rule with the following changes:
7 U.S.C. 3316; Pub. L. 106-107 (31 U.S.C. 6101 note).
(d)
(a) * * *
(1) A recipient of a NIFA competitive grant programs that are awarded under a covered law provided in section 3371 of under the National Agricultural Research, Extension, and Teaching Policy Act of 1977 must provide funds, in-kind contributions, or a combination of both, from sources other than funds provided through such grant in an amount that is at least equal to the amount awarded by NIFA unless an exception applies. NIFA will determine program applicability of this match and include in the RFA for those programs: The match requirement, exceptions, waivers, and any other information necessary to determine applicability of the match requirement. In accordance with section 1492 of the National Agricultural Research, Extension, and Teaching Policy Act of 1977 (7 U.S.C. 3371), as added by section 7128 of the Agricultural Act of 2014 (Pub. L. 113-79), for grants awarded after October 1, 2014, the recipient of an award must provide funds, in-kind contributions, or a combination of both, from sources other than funds provided through such grant in an amount that is at least equal to the amount awarded by NIFA unless one of the exemptions described herein is applicable.
(2) The matching funds requirement does not apply to grants awarded:
(i) To a research agency of the United States Department of Agriculture (USDA); or
(ii) To an entity eligible to receive funds under a capacity and infrastructure program (as defined in section 251(f)(1)(C) of the Department of Agriculture Reorganization Act of 1994, 7 U.S.C. 6971(f)(1)(C)), including a partner of such an entity. Entities eligible to receive funds under a capacity and infrastructure program and exempt from the matching funds requirement include:
(A) 1862 Land-grant Institutions, including State Agricultural Experiment Stations receiving funding under the Hatch Act of 1887;
(B) 1890 Land-grant Institutions;
(C) 1994 Land-grant Institutions;
(D) Entities eligible to receive funds under the of Continuing Animal Health and Disease, Food Security, and Stewardship Research, Education, and Extension Program Funds—Capacity and Infrastructure Program (CIP);
(E) Hispanic-Serving Agricultural Colleges and Universities (HSACU);
(F) Insular Area Schools Eligible to Receive Funds from the Distance Education/Resident Instruction Grant Programs;
(G) Entities eligible to receive funds under the of McIntire-Stennis Cooperative Forestry Program Funds;
(H) Non-Land Grant Colleges of Agriculture (NLGCA)—(for exemption from the new matching requirement, these applications must include NLGCA certification, see instructions for requesting certifications at
(I) Entities eligible to receive funds under a program established under section 1417(b) of the National Agricultural Research, Extension, and Teaching Policy Act of 1977 (7 U.S.C. 3152(b)), including:
(
(
(
(
(J) Individual public or private, nonprofit Alaska Native-Serving and Native Hawaiian-Serving Institutions of higher education (see 20 U.S.C. 1059d).
Indirect cost rates for grants and cooperative agreements shall be determined in accordance with 2 CFR part 200, unless superseded by another authority. Any restriction on indirect costs is to be identified in the request for applications as appropriate. Use of indirect costs as in-kind matching contributions is subject to § 3430.52(b).
(a)* * *
(1) Research in plant breeding, genetics, genomics, and other methods to improve crop characteristics, such as—
(3) Efforts to improve production efficiency, handling and processing, productivity, and profitability over the long term (including specialty crop policy and marketing).
(c) In addition to SCRI grants, NIFA will make competitive research and extension grants under the Emergency Citrus Disease Research and Extension program (see § 3430.209).
(b) The following definitions apply to § 3430.209:
The addition reads as follows:
(b) In awarding grants under § 3430.208, priority will be given to grants that address the research and extension priorities established pursuant to section 1408A of the National Agricultural Research, Extension, and Teaching Policy Act of 1977 (7 U.S.C. 3123a).
In addition to the scientific peer review (
The purpose of this program is to award competitive grants to:
(a) Conduct scientific research and extension activities, technical assistance, and development activities to combat citrus diseases and pests, both domestic and invasive, which pose imminent harm to the United States citrus production and threaten the future viability of the citrus industry, including huanglongbing and the Asian Citrus Psyllid; and
(b) Provide support for the dissemination and commercialization of relevant information, techniques, and technologies discovered pursuant to research and extension activities funded through—
(1) The emergency citrus disease research and extension program; or
(2) Other research and extension projects intended to solve problems caused by citrus production diseases and invasive pests.
The additions read as follows:
(b) * * *
(9) The research and development of surveillance methods, vaccines, vaccination delivery systems, or diagnostic tests for pests and diseases, including—
(i) Epizootic diseases in domestic livestock (including deer, elk, bison, and other animals of the family Cervidae); and
(ii) Zoonotic diseases (including bovine brucellosis and bovine tuberculosis) in domestic livestock or wildlife reservoirs that present a potential concern to public health; and
(10) The identification of animal drug needs and the generation and dissemination of data for safe and effective therapeutic applications of animal drugs for minor species and minor uses of such drugs in major species.
(d) * * *
(4) The effectiveness of conservation practices and technologies designed to address nutrient losses and improve water quality;
(f) * * *
(5) The economic costs, benefits, and viability of producers adopting conservation practices and technologies designed to improve water quality;
(a) The purpose of this program is to make competitive grants, in consultation with the Advisory Board, to support research, education and extension activities regarding organically grown and processed agricultural commodities.
(b) * * *
(1) Facilitating the development and improvement of organic agriculture production, breeding, and processing methods;
(2) Evaluating the potential economic benefits of organic agricultural production and methods to producers, processors, and rural communities;
(6) Conducting advanced on-farm research and development that emphasizes observation of, experimentation with, and innovation for working organic farms, including research relating to production, marketing, food safety, socioeconomic conditions, and farm business management;
(c) A community-based or nongovernmental organization;
(a) * * *
(1) Basic livestock, forest management, and crop farming practices;
(2) Innovative farm, ranch, and private, nonindustrial forest land transfer strategies;
(3) Entrepreneurship and business training;
(4) Financial and risk management training (including the acquisition and management of agricultural credit);
(5) Natural resource management and planning;
(6) Diversification and marketing strategies;
(7) Curriculum development;
(8) Mentoring, apprenticeships, and internships;
(9) Resources and referral;
(10) Farm financial benchmarking;
(11) Assisting beginning farmers or ranchers in acquiring land from retiring farmers and ranchers;
(12) Agricultural rehabilitation and vocational training for veterans;
(13) Farm safety and awareness; and
(14) Other similar subject areas of use to beginning farmers or ranchers.
(b) Partnership and collaboration. In making awards under this subpart, NIFA shall give priority to partnerships and collaborations that are led by or include nongovernmental, and community-based organizations, and school-based agricultural educational organizations with expertise in new agricultural producer training and outreach.
The revision reads as follows:
(a)
(i) Limited resource beginning farmers or ranchers (see 3430.602);
(ii) Socially disadvantaged farmers or ranchers (as defined in section 355(e) of the Consolidated Farm and Rural Development Act (7 U.S.C. 2003(e)) who are beginning farmers or ranchers; and
(iii) Farmworkers desiring to become farmers or ranchers.
(2) Each fiscal year, NIFA shall set aside not less than 5 percent of the funds to support the standard BFRDP projects under this subpart to support programs and services that address the needs of veteran farmers and ranchers (as defined in section 2501(e) of the Food, Agriculture, Conservation, and Trade Act of 1990 (7 U.S.C. 2279(e)). Recipients of these funds may coordinate with a recipient of an award under section 1680 of the Food, Agriculture, Conservation, and Trade Act of 1990 (7 U.S.C. 5933) in addressing the needs of veteran farmers and ranchers with disabilities.
7 U.S.C. 3316; Pub. L. 106-107 (31 U.S.C. 6101 note).
The regulations in this subpart apply to the program authorized under section 1473F of the National Agricultural Research, Extension, and Teaching Policy Act of 1977 (NARETPA), as added by section 7138 of the Food, Conservation, and Energy Act of 2008, (7 U.S.C. 3319i).
The purpose of this program is to make competitive grants to Non Land Grant Colleges of Agriculture (NLGCA) Institutions to assist the NLGCA Institutions in maintaining and expanding the capacity to conduct education, research, and outreach activities relating to agriculture, renewable resources, and other similar disciplines.
The definitions applicable to the program under this subpart include:
(1) A citizen or native resident of a State; or,
(2) A person defined in the Immigration and Nationality Act, 8 U.S.C. 1101(a) (22), who, though not a citizen of the United States, owes permanent allegiance to the United States.
(1) Animal health, production, and well-being.
(2) Plant health and production.
(c) Animal and plant germ plasm collection and preservation.
(3) Aquaculture.
(4) Food safety.
(5) Soil, water, and related resource conservation and improvement.
(6) Forestry, horticulture, and range management.
(7) Nutritional sciences and promotion.
(8) Farm enhancement, including financial management, input efficiency, and profitability.
(9) Home economics (Family and Consumer Sciences).
(10) Rural human ecology.
(11) Youth development and agricultural education, including 4-H clubs.
(12) Expansion of domestic and international markets for agricultural commodities and products, including agricultural trade barrier identification and analysis.
(13) Information management and technology transfer related to agriculture.
(14) Biotechnology related to agriculture.
(15) The processing, distributing, marketing, and utilization of food and agricultural products. (7 U.S.C. Section 3103).
(1) An application for a project:
(i) Which will involve the applicant institution working in cooperation with one or more other entities not legally affiliated with the applicant institution, including other schools, colleges, universities, community colleges, junior colleges, units of State government, private sector organizations, or a consortium of institutions; and
(ii) Where the applicant institution and each cooperating entity will assume a significant role in the conduct of the proposed project.
(2) To demonstrate a substantial involvement with the project, the applicant institution/organization submitting a joint project proposal must retain at least 30 percent but not more than 70 percent of the awarded funds and no cooperating entity may receive less than 10 percent of awarded funds. Only the applicant institution must meet the definition of an eligible institution/organization as specified in this RFA; other entities participating in a joint project proposal are not required to meet the definition of an eligible institution/organization.
(1) An application for a project:
(i) Which will involve the applicant institution/organization working in cooperation with two or more other entities not legally affiliated with the applicant institution, including other schools, colleges, universities, community colleges, junior colleges, units of State government, private sector organizations, or a consortium of institutions; and
(ii) Where the applicant institution and each cooperating entity will assume a significant role in the conduct of the proposed project.
(2) To demonstrate a substantial involvement with the project, the applicant institution/organization submitting a LCI proposal must retain at least 30 percent but not more than 70
(1) Hispanic-serving agricultural colleges and universities; or
(2) Any institution designated under: a. the Act of July 2, 1862 (commonly known as the “First Morrill Act”; 7 U.S.C. 301
(3) The Act of August 30, 1890 (commonly known as the “Second Morrill Act”) (7 U.S.C. 321
(4) The Equity in Educational Land-Grant Status Act of 1994 (Public Law 103-382; 7 U.S.C. 301 note, or the `1994 or Tribal Colleges Land Grants'); or
(5) Public Law 87-788 (commonly known as the “McIntire-Stennis Cooperative Forestry Act”) (16 U.S.C. 582a
(1) Results are intended or unintended consequences of the project, (
(2) Products may be actual items or services acquired with funds, (
(3) Impacts are a measure of the results by comparing what might have happened in the absence of the funded project, (
(1) Where the applicant institution will be the sole entity involved in the execution of the project; or
(2) Which will involve the applicant institution and one or more other entities, but where the involvement of the other entity(ies) does not meet the requirements for a joint project proposal as defined in this section.
(1) Satisfy human food and fiber needs;
(2) Enhance environmental quality and the natural resource base upon which the agriculture economy depends;
(3) Make the most efficient use of nonrenewable resources and on-farm resources and integrate, where appropriate, natural biological cycles and controls;
(4) Sustain the economic viability of farm operations; and
(5) Enhance the quality of life for farmers and society as a whole.
(a)
(b)
(a) For each RFA, NIFA may develop and include the appropriate project types and focus areas based on the critical needs identified through stakeholder input and deemed appropriate by NIFA.
(b) The RFA will specify which of the following project types applicants may submit applications:
(1) Regular project proposal (the applicant executes the project without the requirement of sharing grant funds with other project partners);
(2) Conference/planning grant to facilitate strategic planning session(s);
(3) Joint project proposal (the applicant executes the project with assistance from at least one additional partner and must share grant funds with the additional partner(s)); and
(4) Large-scale (state or region) comprehensive initiatives (LCI) (Applicant + Two or more Partners).
(a) Prohibition against construction. Grant funds awarded under this authority may not be used for the renovation or refurbishment of research, education, or extension space; the purchase or installation of fixed equipment in such space; or the planning, repair, rehabilitation, acquisition, or construction of buildings or facilities.
(b) Prohibition on tuition remission. Tuition remission, on-campus room and board, academic fees or other financial assistance (scholarships or fellowships) are not allowed.
(c) Promotional items (
There are no matching requirements for grants under this subpart.
The term of a Federal assistance award made for a NLGCA project shall not exceed 5 years. No-cost extensions of time beyond the maximum award terms will not be considered or granted.
Rural Housing Service, USDA.
Final rule.
This final rule follows publication of the December 9, 2013, interim final rule and makes changes in response to public comment and further consideration of certain issues by the Rural Housing Service (RHS or Agency) to the Single Family Housing Guaranteed Loan Program (SFHGLP). The changes made by this final rule are designed to further improve and clarify Agency instructions while strengthening and enhancing the SFHGLP process by reducing regulations, improving customer service to achieve greater efficiency, flexibility and effectiveness. This rule will allow RHS to manage the program more effectively and reduce SFHGLP risk of loss.
This rule is effective on March 9, 2016.
Lilian Lipton, Finance and Loan Analyst, Single Family Housing Guaranteed Loan Division, STOP 0784, Room 2250, USDA Rural Development, South Agriculture Building, 1400 Independence Avenue SW., Washington, DC 20250-0784, telephone: (202) 720-1452, email is
This final rule has been determined to be non-significant by the Office of Management and Budget (OMB) under Executive Order 12866.
This rule has been reviewed under Executive Order 12988, Civil Justice Reform. Except where specified, all State and local laws and regulations that are in direct conflict with this rule will be preempted. Federal funds carry Federal requirements. No person is required to apply for funding under this program, but if they do apply and are selected for funding, they must comply with the requirements applicable to the Federal program funds. This rule is not retroactive. It will not affect agreements entered into prior to the effective date of the rule. Before any judicial action may be brought regarding the provisions of this rule, the administrative appeal provisions of 7 CFR part 11 must be exhausted.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effect of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, the Agency generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, or tribal governments, in the aggregate, or to the private sector, of $100 million, or more, in any one year. When such a statement is needed for a rule, section 205 of the UMRA generally requires the Agency to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective, or least burdensome alternative that achieves the objectives of the rule.
This final rule contains no Federal mandates (under the regulatory provisions of Title II of the UMRA) for State, local, and tribal governments or the private sector. Therefore, this rule is not subject to the requirements of sections 202 and 205 of the UMRA.
This document has been reviewed in accordance with 7 CFR part 1940, subpart G, “Environmental Program.” It is the determination of the Agency that this action does not constitute a major Federal action significantly affecting the quality of the human environment, and, in accordance with the National Environmental Policy Act of 1969, Public Law 91-190, neither an Environmental Assessment nor an Environmental Impact Statement is required.
The policies contained in this rule do not have any substantial direct effect on States, on the relationship between the national government and States, or on the distribution of power and responsibilities among the various levels of government. Nor does this rule impose substantial direct compliance costs on State and local governments. Therefore, consultation with the States is not required.
In compliance with the Regulatory Flexibility Act (5 U.S.C. 601
This executive order imposes requirements on Rural Development in the development of regulatory policies that have Tribal implications or preempt tribal laws. Rural Development has determined that the proposed rule does not have a substantial direct effect on one or more Indian Tribe(s) or on either the relationship or the distribution of powers and responsibilities between the Federal Government and Indian Tribes. Thus, this rule is not subject to the requirements of Executive Order 13175. If a Tribe determines that this rule has implications of which RD is not aware and would like to engage with RD on this rule, please contact RD's Native American Coordinator at (720) 544-2911 or
This program/activity is not subject to the provisions of Executive Order 12372, which require intergovernmental consultation with State and local officials. (See the Notice related to 7 CFR part 3015, subpart V, at 48 FR 29112, June 24, 1983; 49 FR 22675, May 31, 1984; 50 FR 14088, April 10, 1985).
This program is listed in the Catalog of Federal Domestic Assistance under Number 10.410, Very Low to Moderate Income Housing Loans (Section 502 Rural Housing Loans).
The information collection and record keeping requirements contained in this regulation have been approved by OMB in accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The Rural Housing Service is committed to complying with the E-Government Act, to promote the use of the Internet and other information technologies to provide increased opportunities for citizen access to Government information and services, and for other purposes.
The U.S. Department of Agriculture (USDA) prohibits discrimination against its customers, employees, and applicants for employment on the bases of race, color, national origin, age, disability, sex, gender identity, religion, reprisal, and where applicable, political beliefs, marital status, familial or parental status, sexual orientation, or all or part of an individual's income is derived from any public assistance program, or protected genetic information in employment or in any program or activity conducted or funded by the Department. (Not all prohibited bases will apply to all programs and/or employment activities.)
If you wish to file a Civil Rights program complaint of discrimination, complete the
Individuals who are deaf, hard of hearing or have speech disabilities and you wish to file either an EEO or program complaint please contact USDA through the Federal Relay Service at (800) 877-8339 or (800) 845-6136 (in Spanish).
Persons with disabilities who wish to file a program complaint, please see information above on how to contact us by mail directly or by email. If you require alternative means of communication for program information (
On December 9, 2013, at 78 FR 73928, RHS published for public comment an interim final rule (December 2013 interim final rule) to replace an existing rule and process that was outdated. The December 2013 interim final rule submitted for public comment was intended to make the process of utilizing the SFHGLP clearer and streamlined in an effort to achieve greater efficiency, flexibility and effectiveness in managing the SFHGLP. The principles that guided RHS in the development of this rule are included in the December 2013 interim final rule.
The public comment period for the December 2013 interim final rule closed on January 8, 2014. The effective date of implementation was to occur on September 1, 2014. In response to numerous requests to extend the implementation period and the desire of RHS to allow ample time for lenders and consumers to receive training and implement changes that occurred with the implementation of the interim final rule, RHS announced a delayed implementation date. This announcement was made by publication of a notice in the
This final rule follows publication of the December 9, 2013, interim final rule and takes into consideration the public comments received. The public comment period on the interim final rule closed on January 8, 2014. RHS received comments from twelve respondents consisting of eight lenders, an Agency employee and two interest groups. The comments were not substantive in nature, resulting in minor changes to the final rule. Most commenters were supportive of the interim final rule and commenters were satisfied with the technical guidance provided in the accompanying release of the Technical Handbook, “SFH Guaranteed Loan Program Technical Handbook” which accompanied the December 2013 interim final rule, available at:
After careful consideration of the issues raised by the commenters, RHS will adopt an amended version of the interim final rule. None of the changes are considered material. Specifically RHS has made the following changes to the December 2013 interim final rule:
1.
2.
3.
4.
5.
6.
7.
8.
The following section of the preamble presents a summary of substantive issues raised by the public in response to the December 2013 interim final rule and the RHS response to these issues.
Special loan servicing is permitted one time over the life of the loan. RHS has not amended the final rule in response to this comment.
Home improvement, Loan Programs—Housing and community development, Mortgage insurance, Mortgages, Rural areas.
For the reason stated in the preamble, chapter XVIII, part 3555, title 7 of the Code of Federal Regulations is amended as follows:
5 U.S.C. 301, 42 U.S.C. 1471
(d) * * *
(5) The lender must comply with Federally mandated flood insurance purchase requirements. Existing dwellings in a SFHA are not eligible under the SFHGLP unless flood insurance through the FEMA National Flood Insurance Program (NFIP) is available for the community and flood insurance, whether NFIP, “write your own,” or private flood insurance, is purchased by the borrower. The lender will require the borrower to obtain, and maintain for the term of the mortgage, flood insurance for any property located in a SFHA, listing the lender as a loss payee. Purchase of existing structures within the federally regulated floodplain will not require consideration of alternatives to avoid adverse effects and incompatible development in floodplains;
(6) The borrower must obtain, and continuously maintain for the life of the mortgage, flood insurance on the security property in an amount sufficient to protect the property securing the guaranteed loan. Flood insurance policies must be issued under the NFIP, or by a licensed property and casualty insurance company authorized to participate in NFIP's “Write Your Own” program or private flood insurance policy, as approved by the lender. Lenders are required to accept private flood insurance policies, when purchased by a borrower, that meet the requirements of 42 U.S.C. 4012a (b)(1)(A). Lenders remain responsible to ensure a private flood insurance policy meets the requirements of 42 U.S.C. 4012a (b)(1)(A).
(7) Rural Development will not guarantee loans for new or proposed homes in an SFHA unless the lender obtains a final Letter of Map Amendment (LOMA) or a final Letter of Map Revision (LOMR) that removes the property from the SFHA, or performs an alternatives analysis in compliance with the Agencies National Environmental Policy Act regulation and obtains a FEMA elevation certificate that shows that the lowest floor (including basement) of the dwelling and all related building improvements are built at or above the 100-year flood plain elevation in compliance with the NFIP.
(b) * * *
(6) * * *
(vi) Reasonable and customary loan discount points to reduce the note interest rate from the rate authorized in § 3555.104(a).
(x) The amount of the loan up-front guarantee fee required by § 3555.107(g).
(xi) The cost of establishing a cushion in the mortgage escrow account for payment of the annual fee required by § 3555.107(h), not to exceed 2 months.
(d) * * *
(3) * * *
(vi) Two options for refinancing can be offered. Lenders may offer a streamlined refinance for existing Section 502 Guaranteed loans, which does not require a new appraisal. Streamlined financing may not be available for existing Section 502 Direct loans. The lender will pay off the principal balance of the existing Section 502 Guaranteed loan. The new loan amount cannot include any accrued interest, closing costs or lender fees. The refinance up-front guarantee fee as established by the Agency can be included in the loan to be refinanced to the extent financing does not exceed the original loan amount. Lenders may offer non-streamlined refinancing for existing Section 502 Guaranteed or Direct loans, which requires a new and current market value appraisal. The new loan may include the principal and interest of the existing Agency loan, reasonable closing costs and lenders fees to extent there is sufficient equity in the property as determined by an appraisal. The appraised value may be exceeded by the amount of up-front guarantee fee financed, if any, when using the non-streamlined option. Documentation, costs, and underwriting requirements of subparts D, E, and F of this part apply to refinances, unless otherwise provided by the Agency.
(a)
(a) * * *
(3) Does not exceed the Fannie Mae rate for 30 year fixed rate conventional loans, as authorized in Exhibit B of subpart A of part 1810 of this Chapter (RD Instruction 440.1, available in any Rural Development office) or online at:
(c) * * *
(1) The loan is to finance the construction and purchase of a single family housing residence. Condominiums are ineligible for combination construction and permanent loans.
(d) * * *
(3) Annual fees will begin in the month immediately following loan closing and will not be affected by loan reamortization following the completion of construction. Lenders may fund a lender imposed escrow account for borrower payments of the annual fee in accordance with § 3555.101(b)(6)(xi), as an eligible loan purpose, provided the market value of the property is not exceeded.
(h)
(d)
(h) * * *
(2) The repayment ratio may exceed the percentage specified in paragraph (h)(1) of this section if certain compensating factors exist. The handbook will define when a debt ratio waiver may be granted. The automated underwriting system will take into account any compensating factors in determining whether the variance is appropriate. For manually underwritten loans, the lender must document compensating factors demonstrating that the household has higher repayment ability based on its capacity, willingness and ability to pay mortgage payments in a timely manner. The presence of compensating factors does not strengthen a ratio exception when multiple layers of risk, such as a marginal credit history, are present in the application. Acceptable compensating factors and supporting documentation for a proposed debt ratio waiver will be further defined and clarified in the handbook. Compensating factors include, but are not limited to:
(i) * * *
(2) A loan's acceptance by an Agency approved automated underwriting system eliminates the need for the lender to submit documentation of the credit qualification decision as loan approval requirements will be incorporated in the automated system.
(3) * * *
(ii) A bankruptcy in which debts were discharged within 36 months prior to the date of application by the applicant. A lender may give favorable consideration to applicants who have entered into a bankruptcy debt restructuring plan who have completed 12 months of consecutive payments. The payment performance must have been satisfactory with all required payments made on time, and the Trustee or the Bankruptcy Judge must approve of the new credit.
(a) * * *
(2) Site development work properly completed to HUD, state and local government standards, as well as the manufacturer's requirements for installation on a permanent foundation.
Lenders may release security instruments only after payment for the satisfaction of the full debt, including any recapture, has been received and verified.
(b) * * *
(2) * * *
(vi) A new guarantee fee, calculated based on the remaining principal balance, must be paid to Rural Development in accordance with § 3555.107(g).
(e)
(f)
Lenders may pay the following pre-liquidation expenses necessary to protect the security property and charge the cost against the borrower's account.
The revisions and addition read as follows:
(b) * * *
(3)
(i) Loan modifications must be a fixed interest rate and cannot exceed the interest rate of the loan note guarantee issued.
(iii) If necessary to demonstrate repayment ability, the loan term after reamortization may be extended for up to 30 years from the date of the loan modification.
(v) The borrower is not required to complete a trial payment plan prior to making the scheduled payments amended by the traditional loan servicing loan modification.
(c)
(c)
(1) The interest rate must be fixed. The interest rate cannot exceed the interest rate of the loan note guarantee issued. When reducing the interest rate, the maximum rate is subject to paragraph (c)(2) of this section.
(2) The Agency may establish the maximum allowable interest rate by publishing a notice of a change in interest rate. A notice of change in interest rate will be published as authorized in Exhibit B of subpart A of part 1810 of this chapter (RD Instruction 440.1, available in any Rural Development office) or online at
(c) Unless State law imposes other requirements, the lender may reinstate an accelerated account if the borrower pays, or makes acceptable arrangements to pay, all past-due amounts, any protective advances, and any foreclosure-related costs incurred by the lender.
(f) * * *
(1) The lender must prepare and maintain a disposition plan on all acquired properties. The lender will submit the property disposition plan and any subsequent changes for Agency concurrence in a timely manner as specified by the Agency. The lender may obtain a waiver of the concurrence requirement as provided for in § 3555.301(h). The plan will include the proposed method for sale of the property, the estimated value based on an appraisal, minimum sale price, itemized estimated costs of the sale, and any other information that could impact the amount of loss on the loan.
(c)
U.S. Customs and Border Protection, DHS.
Interim final rule; solicitation of comments.
This interim final rule revises Department of Homeland Security regulations to eliminate the nonimmigrant visa exemption for certain Caribbean residents seeking to come to the United States as H-2A agricultural workers and the spouses or children who accompany or follow these workers to the United States. As a result, these nonimmigrants will be required to have both a valid passport and visa. The Department of State is revising its parallel regulations.
Please submit comments, identified by docket number, by one of the following methods:
•
•
Rafael Henry, U.S. Customs and Border Protection, Office of Field Operations, (202) 344-3251, or via email at
Interested persons are invited to submit written comments on all aspects of this interim final rule. U.S. Customs and Border Protection (CBP) also invites comments on the economic, environmental, or federalism effects of this rule. We urge commenters to reference a specific portion of the rule, explain the reason for any recommended change, and include data, information, or authorities that support such recommended change.
In general, nonimmigrant aliens are required to present an unexpired passport and a valid unexpired visa in order to be admitted to the United States.
The H-2A nonimmigrant classification applies to an alien seeking to enter the United States to perform agricultural labor or services of a temporary or seasonal nature in the United States. Generally, H-2A agricultural workers are required to possess and present both a passport and a valid unexpired H-2A visa when entering the United States. Certain residents of the Caribbean, however, are exempted by regulation from having to possess and present a valid unexpired H-2A visa, and only must possess and present a valid unexpired passport to be admitted to the United States as a temporary agricultural worker.
Specifically, a visa is currently not required for H-2A agricultural workers who are British, French, or Netherlands nationals, or nationals of Barbados, Grenada, Jamaica, or Trinidad and Tobago, who have their residence in British, French, or Netherlands territory located in the adjacent islands of the Caribbean area, or in Barbados, Grenada, Jamaica, or Trinidad and Tobago. 8 CFR 212.1(b)(1)(i). Additionally, a visa is currently not required for the spouse or child accompanying or following to join such an H-2A agricultural worker. 8 CFR 212.1(b)(1)(iii). The current regulation also provides that a visa is not required for the beneficiary of a valid, unexpired indefinite certification granted by the Department of Labor (DOL) for employment in the U.S. Virgin Islands, if the beneficiary is proceeding to those islands for such purpose and is a British, French, or Netherlands national, or national of Barbados, Grenada, Jamaica, or Trinidad and Tobago, who has his or her residence in British, French, or Netherlands territory located in the adjacent islands of the Caribbean area, or in Barbados, Grenada, Jamaica, or Trinidad and Tobago. The regulation also provides that a visa is not required for the spouse or child accompanying or following to join such a beneficiary. 8 CFR 212.1(b)(1)(ii)-(iii). Department of State (State) regulations also describe the visa exemption for these classes of Caribbean residents.
The visa exemption for agricultural workers from the specified Caribbean countries dates back more than 70 years and was created primarily to address U.S. labor shortages during World War II by expeditiously providing a source of agricultural workers from the British Caribbean to meet the needs of agricultural employers in the southeastern United States. Given the passage of time, this basis for the exemption no longer justifies it.
Since H-2A agricultural workers from the specified Caribbean countries are exempt from the visa requirement, they do not undergo the same visa issuance process as H-2A applicants from other countries. The absence of a visa requirement for these H-2A workers means that these individuals do not undergo a face-to-face consular interview, the adjudication of the applicants eligibility and qualification for the intended position, screening for potential fraudulent employment, and the associated fingerprint and security checks prior to seeking admission at a U.S. port of entry. Further, in the absence of the visa requirement, there is significantly less advance opportunity for the U.S. Government to determine whether other requirements for H-2A classification, such as the bar to collection of prohibited fees from prospective H-2 workers, have been satisfied.
DHS, in conjunction with the Department of State (“State”), has determined that the nonimmigrant visa exemption for these classes of Caribbean residents, coming to the United States as H-2A agricultural workers or as the spouses or children accompanying or following these workers, is outdated and incongruent with the visa requirement for other H-2A agricultural workers from other countries. DHS and State believe that eliminating the visa exemption furthers the national security interests of the United States.
The application of the general visa requirement to the class of Caribbean agricultural workers described above will ensure that these applicants for admission, like other H-2A agricultural workers, are sufficiently screened via State's visa issuance process prior to arrival in the United States. In addition, the visa requirement will ensure that these persons possess evidence of the intended purpose of their stay in the
Furthermore, extending the visa requirement to these Caribbean H-2A agricultural workers will allow U.S. Government officials to interview prospective H-2A workers and will help to better ensure that such workers are protected from certain employment and recruitment-based abuses, including, but not limited to, the imposition of fees prohibited under 8 CFR 214.2(h)(5)(xi). In addition, the visa requirement will help ensure that agricultural workers have been informed, and are aware of, their rights and responsibilities before departing from their home countries to engage in H-2A agricultural work.
As a result of the termination of the relevant worker program in the U.S. Virgin Islands, DOL no longer grants indefinite certifications for employment in the U.S. Virgin Islands.
Accordingly, DHS, in conjunction with State, is eliminating the visa exemption for these Caribbean H-2A agricultural workers and the spouses or children accompanying or following these workers. 8 CFR 212.1(b)(1). This means that, in addition to a valid passport, these nonimmigrant aliens are now required to obtain a nonimmigrant visa prior to traveling to the United States. In order to obtain a visa, these nonimmigrant aliens will have to submit a visa application to and appear for an interview at the applicable U.S. embassy
As a result of the elimination of 8 CFR 212.1(b)(1), current 8 CFR 212.1(b)(2) is being redesignated as 8 CFR 212.1(b). DHS is also making a technical correction updating the language in current 8 CFR 212.1(b)(2)(ii)(C) referring to “a current
The implementation of this rule as an interim final rule, with provisions for post-promulgation public comments, is based on the good cause exception found in section 553 of the Administrative Procedure Act (APA) (5 U.S.C. 553(b)(B)). There is reasonable concern that publication of the rule as a proposed rule, which would permit continuation of the current visa exemption, could lead to an increase in applications for admissions in bad faith by persons who would otherwise have been denied visas and are seeking to avoid the visa requirement and consular screening process during the period between the publication of a proposed and a final rule. Accordingly, DHS finds that it is impracticable and contrary to the public interest to publish this rule with prior notice and comment period. Under the good cause exception, this rule is exempt from the notice and comment and delayed effective date requirements of the APA.
In addition, DHS is of the opinion that eliminating the visa exemption and requiring a visa for Caribbean H-2A agricultural workers, and the spouses or children accompanying or following these workers, is a foreign affairs function of the U.S. Government under section 553(a) of the APA (5 U.S.C. 553(a)). As this rule implements this function, DHS is of the opinion that this rule is also exempt from the notice and comment and 30-day delayed effective date requirements of the APA by virtue of the foreign affairs exception in 5 U.S.C. 553(a)(1). DHS is nevertheless providing the opportunity for the public to provide comments.
Executive Orders 13563 and 12866 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. DHS is of the opinion this rule is not subject to the requirements of Executive Orders 13563 and 12866, due to the foreign affairs exception described above. However, DHS has nevertheless reviewed the interim final rule to ensure its consistency with the regulatory philosophy and principles set forth in those Executive Orders.
Currently, British, French, and Netherlands nationals and nationals of Barbados, Grenada, Jamaica, and Trinidad and Tobago, who have their residence in British, French, or Netherlands territory located in the adjacent islands of the Caribbean area or in Barbados, Grenada, Jamaica, or Trinidad and Tobago, are not required to obtain a visa before traveling to the United States as H-2A agricultural workers. This rule would require these prospective H-2A agricultural workers to obtain a visa prior to travel to the United States. Any spouses or children of these workers will also now have to obtain a visa before being brought to the United States. Since more than 99 percent of such workers
Data on the number of visa applications Jamaican travelers would need to obtain as a result of this rule is not available. A USCIS database tracks the number of petitions for H-2A workers from Jamaica, but does not include the spouses or children who would now also need visas to travel to the United States. A CBP database tracks the number of Jamaican nationals arriving under the H-2A program, but counts multiple arrivals by a single person as separate arrivals. For the purposes of this analysis, we use the number of petitions as our primary estimate of the number of visas that
Employers petitioned on behalf of an annual average of 165 workers from Jamaica under this program from FY 2011-2013,
Under this rule, workers would have to apply for a visa using Form DS-160 and undergo an interview at a U.S. embassy or consulate prior to traveling to the United States. According to the Paperwork Reduction Act estimate for Form DS-160, the Department of State estimates that the visa application takes 1.25 hours to complete. The interview itself typically lasts approximately 5-10 minutes; however, when accounting for potential wait time, the interview process may take up to 2 hours. Since the only U.S. embassy in Jamaica is in Kingston, visa applicants may have to travel up to 3.5 hours each way to appear for an interview, depending on their location. We therefore assume that filling out the D-160, traveling to and from the embassy for the visa interview, and the visa interview itself will require a total of 10.25 hours of the applicant's time. To the extent the actual time burden to travel to and from the interview is less than we estimated, costs would be lower. Using the average Jamaican wage rate of $3.25/hour
We are unable to quantify the benefits of this rule; therefore we discuss the benefits qualitatively. Requiring these prospective H-2A agricultural workers to obtain visas will ensure that they are properly screened prior to arrival in the United States. This will lessen the possibility that a person who poses a security risk to the United States and other potential immigration violators may improperly gain admission to the United States. DHS has determined that visitors from the countries affected by this rule are not a lower security risk than those coming from other countries; therefore, CBP believes that they should be subject to the same screening prior to arriving at their port of entry. Also, prescreening and appearing before consular officers will provide greater opportunities to ensure compliance with DHS and DOL H-2A rules, including those regulatory provisions prohibiting charging fees to workers in connection with or as a condition of their employment or recruitment.
The Regulatory Flexibility Act (5 U.S.C. 601
Administrative practice and procedure, Aliens, Immigration, Passports and visas, Reporting and recordkeeping requirements.
Part 212 of title 8 of the Code of Federal Regulations is amended as set forth below:
8 U.S.C. 1101 and note, 1102, 1103, 1182 and note, 1184, 1187, 1223, 1225, 1226, 1227, 1255, 1359; 8 U.S.C. 1185 note (section 7209 of Public Law 108-458); 8 CFR part 2.
Section 212.1(q) also issued under section 702, Public Law 110-229, 122 Stat. 754, 854.
(b)
(1) The alien is seeking admission solely to visit the Virgin Islands of the United States; or
(2) At the time of embarking on an aircraft at St. Thomas, U.S. Virgin Islands, the alien meets each of the following requirements:
(i) The alien is traveling to any other part of the United States by aircraft as a nonimmigrant visitor for business or pleasure (as described in section 101(a)(15)(B) of the Act);
(ii) The alien satisfies the examining U.S. immigration officer at the port-of-entry that he or she is clearly and beyond doubt entitled to admission in all other respects; and
(iii) The alien presents a current certificate issued by the Royal Virgin Islands Police Force indicating that he or she has no criminal record.
Community Development Financial Institutions Fund, Department of the Treasury.
Interim rule with request for public comment.
The Department of the Treasury is issuing an interim rule implementing the Capital Magnet Fund (CMF), administered by the Community Development Financial Institutions Fund (CDFI Fund). This interim rule incorporates updates to the definitions, requirements and parameters for CMF implementation and administration. In addition, sections of the CMF interim rule regarding certain definitions and project level requirements are revised in order to facilitate alignment with other federal housing programs and ease of administration. These revisions are modeled after the credit requirements for Low Income Housing Credits (LIHTCs) under section 42 of the Internal Revenue Code of 1986, as amended, and the program requirements of the HOME Investment Partnership Program (HOME Program) authorized under Title II of the Cranston-Gonzalez National Affordable Housing Act, as amended, and the HOME Program final rule published on July 24, 2013.
This interim rule also reflects requirements set forth in a final rule, Uniform Administrative Requirements, Cost Principles and Audit Requirements for Federal Awards, adopted by the Department of the Treasury on December 19, 2014 (hereafter referred to as the Uniform Administrative Requirements). The Uniform Administrative Requirements constitute a government-wide framework for grants management codified by the Office of Management and Budget (OMB), combining several OMB grants management circulars aimed at reducing the administrative burden for Recipients, and reducing the risk of waste, fraud and abuse of Federal financial assistance. The Uniform Administrative Requirements establish financial, administrative, procurement, and program management standards with which Federal award-making programs, including those administered by the CDFI Fund, and Recipients must comply. Accordingly, this interim rule includes revisions necessary to implement the Uniform Administrative Requirements, as well as to make certain technical corrections and certain programmatic updates, as well as provide clarifying language to existing program requirements.
You may submit comments concerning this interim rule via the Federal e-Rulemaking Portal at
Marcia Sigal, CMF Program Manager, Community Development Financial Institutions Fund, at
The Capital Magnet Fund (CMF) was established through the Housing and Economic Recovery Act of 2008 (the Act), Public Law 110-289, section 1131, as a trust fund, the appropriation to which was used to carry out a competitive grant program administered by the CDFI Fund. The mission of the CDFI Fund is to increase economic opportunity and promote community development investments for underserved populations and in distressed communities in the United States. Its long term vision is an America in which all people have access to affordable credit, capital and financial services.
The Act requires Fannie Mae and Freddie Mac to set aside an amount equal to 4.2 basis points for each dollar of their unpaid principal balances of total new business purchases to be allocated to the Housing Trust Fund (administered by the Department of Housing and Urban Development) and the Capital Magnet Fund. The Act also provides the Federal Housing Finance Agency (FHFA) with the authority to temporarily suspend these allocations upon certain findings. On November 13, 2008, the Director of the FHFA temporarily suspended the allocation of funds. On December 11, 2014, the Director of the FHFA terminated the temporary suspension of those allocations, directing Fannie Mae and Freddie Mac to begin setting aside and allocating funds to the Housing Trust Fund and the Capital Magnet Fund. Accordingly, the CDFI Fund is promulgating this revised interim rule in anticipation of future Capital Magnet Fund application rounds.
Through the CMF, the CDFI Fund is authorized to make financial assistance grants to Certified Community Development Financial Institutions (CDFIs) and Nonprofit Organizations (if one of their principal purposes is the development or management of affordable housing). CMF Awards must be used to attract private financing for and increase investment in: (i) The Development, Preservation, Rehabilitation, and Purchase of Affordable Housing for primarily Extremely Low-, Very Low-, and Low-Income Families; and (ii) Economic Development Activities which, In Conjunction With Affordable Housing Activities will implement a Concerted Strategy to stabilize or revitalize a Low-Income Area or Underserved Rural Area.
All capitalized terms herein are defined in the definitions section of the interim rule, as set forth in 12 CFR 1807.104.
The comment period for the December 3, 2010, Interim Rule ended on February 1, 2011. The CDFI Fund received one written comment. The commenter asserted that the December 3, 2010, Interim Rule did not allow market-based Section 8 vouchers to be used to satisfy CMF affordability requirements and that the interim rule should make clear that, in the event a tenant or a unit in a Multi-family housing project receives a Federal or State rental subsidy, the maximum rent that can be charged is the amount allowable under such program. The commenter suggested that the interim rule should provide for a rent floor of the project's initial rents, in the event median incomes decrease. The commenter also suggested that the rent limitation should be adjusted by the number of bedrooms in the unit.
In this revised interim rule (at 12 CFR 1807.401(a) and (e)), the CDFI Fund incorporates the commenter's suggestions regarding Federal or State rental subsidy and the creation of a rent floor for projects. The CDFI Fund also adopts the commenter's suggestion that rent limitations be adjusted by the
Substantive revisions to the interim rule (meaning, revisions other than the insertion of new language that clarifies existing program requirements) fall generally into three categories: (i) Adoption of policy priorities, programmatic changes/clarifications, and technical corrections; (ii) alignment with the Uniform Administrative Requirements; and (iii) alignment with HOME Program requirements and with requirements to qualify for LIHTCs.
Recent efforts supported by the White House Rental Housing Policy Working Group, which established joint working groups comprised of staff from the U.S. Department of Housing and Urban Development (HUD), the U.S. Department of Agriculture (USDA), and the U.S. Department of the Treasury have highlighted the need for alignment amongst federally subsidized affordable housing program requirements. The CDFI Fund has determined that Recipients' use of CMF Awards better aligns with LIHTCs (as opposed to benefits under the HOME Program) in several key respects, specifically with regard to Project-level requirements. Thus, this interim rule incorporates some requirements to qualify for LIHTCs and removes certain requirements that, in the December 10, 2010, CMF Program interim rule, were modeled after the HOME Program.
A.
B.
C.
D.
E.
F.
G.
H.
I.
J.
K.
It has been determined that this interim rule is not a significant regulatory action under Executive Order 12866. Accordingly, a regulatory impact assessment is not required.
Because no notice of proposed rulemaking is required under the Administrative Procedure Act (5 U.S.C 553), or any other law, the Regulatory Flexibility Act does not apply.
The collections of information contained in this interim rule will be reviewed and approved by the Office of Management and Budget (OMB) in accordance with the Paperwork Reduction Act of 1995 and assigned the applicable, approved OMB Control Numbers associated with the CDFI Fund under 1559-XXXX. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a valid control number assigned by OMB. This document restates the collections of information without substantive change.
This interim rule has been reviewed in accordance with the CDFI Fund's environmental quality regulations (12 CFR part 1815), promulgated pursuant to the National Environmental Protection Act of 1969 (NEPA), which requires that the CDFI Fund adequately consider the cumulative impact proposed activities have upon the human environment. It is the determination of the CDFI Fund that the interim rule does not constitute a major federal action significantly affecting the quality of the human environment and, in accordance with the NEPA and the CDFI Fund's environmental quality regulations (12 CFR part 1815), neither an Environmental Assessment nor an Environmental Impact Statement is required.
Because the revisions to this interim rule relate to loans and grants, notice and public procedure and a delayed effective date are not required pursuant to the Administrative Procedure Act, 5 U.S.C. 553(a)(2).
Public comment is solicited on all aspects of this interim rule. The CDFI Fund will consider all comments made on the substance of this interim rule, but it does not intend to hold hearings.
Capital Magnet Fund—21.011.
Community development, Grant programs—housing and community development, Reporting and record keeping requirements.
12 U.S.C. 4569.
The purpose of the Capital Magnet Fund (CMF) is to attract private capital for and increase investment in Affordable Housing Activities and related Economic Development Activities.
(a) Through the CMF, the CDFI Fund competitively awards grants to CDFIs and qualified Nonprofit Organizations to leverage dollars for:
(1) The Development, Preservation, Rehabilitation or Purchase of Affordable Housing primarily for Low-Income Families; and
(2) Financing Economic Development Activities.
(b) The CDFI Fund will select Recipients to receive CMF Awards through a merit-based, competitive application process. CMF Awards may only be used for eligible uses set forth in subpart C of this part. Each Recipient will enter into an Assistance Agreement that will require it to leverage the CMF Award amount and abide by other terms and conditions pertinent to any assistance received under this part.
Restrictions on applying for, receiving, and using CMF Awards in conjunction with awards under other programs administered by the CDFI Fund (including, but not limited to, the Bank Enterprise Award Program, the CDFI Program, the CDFI Bond Guarantee Program, the Native American CDFI Assistance (NACA) Program, and the New Markets Tax Credit Program) are as set forth in the applicable Notice of Funds Availability, Notice of Guarantee Availability, or Notice of Allocation Availability.
No Recipient shall be deemed to be an agency, department, or instrumentality of the United States.
For the purpose of this part:
(1) Managed by the Recipient; and
(2) Uses its capital to finance Affordable Housing Activities;
(1) Ownership, control, or power to vote 25 percent or more of the outstanding shares of any class of Voting Securities of any company, directly or indirectly or acting through one or more other persons;
(2) Control in any manner over the election of a majority of the directors, trustees, or general partners (or individuals exercising similar functions) of any company; or
(3) The power to exercise, directly or indirectly, a controlling influence over the management, credit or investment decisions, or policies of any company;
(1) Having, in the case of owner-occupied Housing units, annual income not in excess of 120 percent of the area median income adjusted for Family size in the same manner as HUD makes these adjustments for its other published income limits; and
(2) Having, in the case of rental Housing units, annual income not in excess of 120 percent of the area median income, adjusted for Family size in the same manner as HUD makes these adjustments for its published income limits;
(1) Having, in the case of owner-occupied Housing units, income not in excess of 30 percent of the area median
(2) Having, in the case of rental Housing units, income not in excess of 30 percent of the area median income, adjusted for Family size, as determined by HUD, except that HUD may establish income ceilings higher or lower than 30 percent of the median for the area on the basis of HUD findings that such variations are necessary because of prevailing levels of construction costs or fair market rents, or unusually high or low Family incomes;
(1) Except as otherwise provided in paragraphs (1)(i), (ii), and (iii) of this definition, the land may be owned in fee simple or the homeowner may have a 99-year ground lease;
(i) For Housing located on Indian trust or restricted Indian lands, the ground lease must be for 50 years or more;
(ii) For Housing located in Guam, the Northern Mariana Islands, the U. S. Virgin Islands, and American Samoa, the ground lease must be 40 years or more;
(iii) For manufactured housing, the ground lease must be for a minimum period of 10 years or such other applicable time period regarding location set forth in this definition of Homeownership at the time of purchase by the homeowner;
(2) Ownership interest may not merely consist of a right to possession under a contract for deed, installment contract, or land contract (pursuant to which the deed is not given until the final payment is made);
(3) Ownership interest may only be subject to the restrictions on resale permitted under the Assistance Agreement and this part; mortgages, deeds of trust, or other liens or instruments securing debt on the property; or any other restrictions or encumbrances that do not impair the good and marketable nature of title to the ownership interest;
(1) Physically proximate to; and
(2) Reasonably available to residents of Affordable Housing that is subject to Affordable Housing Activities. For a Metropolitan Area, In Conjunction With means located within the same census tract or within 1 mile of such Affordable Housing. For a Non-Metropolitan Area, In Conjunction With means located within the same county, township, or village, or within 10 miles of such Affordable Housing;
(1) Having, in the case of owner-occupied Housing units, income not in excess of 80 percent of area median income, adjusted for Family size, as determined by HUD, except that HUD may establish income ceilings higher or lower than 80 percent of the median for the area on the basis of HUD findings that such variations are necessary because of prevailing levels of construction costs or fair market rents, or unusually high or low Family incomes; and
(2) Having, in the case of rental Housing units, income not in excess of 80 percent of area median income, adjusted for Family size, as determined by HUD, except that HUD may establish income ceilings higher or lower than 80 percent of the median for the area on the basis of HUD findings that such variations are necessary because of prevailing levels of construction costs or fair market rents, or unusually high or low Family incomes;
(1) Designated as a nonprofit or not-for-profit entity under the laws of the organization's State of formation; and
(2) Exempt from Federal income taxation pursuant to the Internal Revenue Code of 1986;
(1) Activities to refinance, with or without Rehabilitation, Single-family housing or Multi-family housing (rental) mortgages that, at the time of refinancing, are subject to affordability and use restrictions under the LIHTC statute or under State or Federal affordable housing programs, including but not limited to, the HOME Program, properties with Federal project-based rental assistance, or the USDA rental housing programs, hereinafter referred to as “similar State or Federal affordable housing programs,” where such refinancing has the effect of extending the term of any existing affordability and use restrictions on the properties by a minimum 10 years or as otherwise specified in the Assistance Agreement;
(2) Activities to refinance and acquire Single-family housing or Multi-family housing that, at the time of refinancing or acquisition, were subject to affordability and use restrictions under similar State or Federal affordable housing programs or under the LIHTC statute, by the former tenants of such properties, where such refinancing has the effect of extending the term of any existing affordability and use restrictions on the properties by a minimum 10 years or as otherwise specified in the Assistance Agreement;
(3) Activities to refinance the mortgages of owner-occupied, Single-family housing that, at the time of refinancing, are subject to affordability and use restrictions under similar State or Federal affordable housing programs, where such refinancing has the effect of extending the term of any existing affordability and use restrictions on the properties by a minimum 10 years or as otherwise specified in the Assistance Agreement;
(4) Activities to acquire Single-family housing or Multi-family housing, with or without Rehabilitation, with the commitment to subject the properties to the affordability qualifications set forth in subpart D of this part; or
(5) Activities to refinance, with or without Rehabilitation, Single-family housing or Multi-family housing, with the commitment to subject the properties to the affordability qualifications set forth in subpart D of this part;
(1) A Non-Metropolitan Area that:
(i) Qualifies as a Low-Income Area; and
(ii) Is experiencing economic distress evidenced by 30 percent or more of resident households with one or more of these four housing conditions in the most recent census for which data are available:
(A) Lacking complete plumbing;
(B) Lacking complete kitchen;
(C) Paying 30 percent or more of income for owner costs or tenant rent; or
(D) Having more than 1 person per room;
(2) An area as specified in the applicable NOFA and/or Assistance Agreement;
(1) Having, in the case of owner-occupied Housing, income not greater than 50 percent of the area median income with adjustments for Family size, as determined by HUD, except that HUD may establish income ceilings higher or lower than 50 percent of the median for the area on the basis of HUD findings that such variations are necessary because of prevailing levels of construction costs or fair market rents, or unusually high or low Family incomes; and
(2) Having, in the case of rental Housing, income not greater than 50 percent of the area median income, with adjustments for Family size, as determined by HUD, except that HUD may establish income ceilings higher or lower than 50 percent of the median for the area on the basis of HUD findings that such variations are necessary because of prevailing levels of construction costs or fair market rents, or unusually high or low Family incomes.
The CDFI Fund may waive any requirement of this part that is not required by law upon a determination of good cause. Each such waiver shall be in writing and supported by a statement of the facts and the grounds forming the basis of the waiver. For a waiver in an individual case, the CDFI Fund must determine that application of the requirement to be waived would adversely affect the achievement of the purposes of the Act. For waivers of general applicability, the CDFI Fund will publish notification of granted waivers in the
The OMB control number for the CMF Award application is 1559-0036. The compliance date requirements for the collection of information in § 1807.902 is stayed indefinitely, pending Office of Management and Budget approval and assignment of an OMB control number.
As of February 8, 2016, the regulations of this part are applicable for CMF Awards made pursuant to Notices of Funds Availability published after February 8, 2016.
(a)
(1) A Certified CDFI. An entity may meet the requirements described in this paragraph (a)(1) if it is:
(i) A Certified CDFI, as set forth in 12 CFR 1805.201,
(ii) A Certified CDFI that has been in existence as a legally formed entity as set forth in the applicable Notice of Funds Availability (NOFA); or
(2) A Nonprofit Organization having as one of its principal purposes the development or management of affordable housing. An entity may meet the requirements described in this paragraph (a)(2) if it:
(i) Has been in existence as a legally formed entity as set forth in the applicable NOFA;
(ii) Demonstrates, through articles of incorporation, by-laws, or other board-approved documents, that the development or management of affordable housing are among its principal purposes; and
(iii) Can demonstrate that a certain percentage, set forth in the applicable NOFA, of the Applicant's total assets are dedicated to the development or management of affordable housing.
(b)
Each Recipient must use its CMF Award for the eligible activities described in § 1807.301 so long as such eligible activities increase private capital for and increase investment in:
(a) Development, Preservation, Rehabilitation, and/or Purchase of Affordable Housing for primarily Extremely Low-Income, Very Low-Income, and Low-Income Families; and/or
(b) Economic Development Activities.
(1) Economic Development Activity must support Affordable Housing;
(2) The Recipient may undertake Economic Development Activity In Conjunction With Affordable Housing Activities that are undertaken by parties other than the Recipient;
(3) If the Recipient uses its CMF Award to fund an Economic Development Activity In Conjunction With Affordable Housing Activity, it must track the resulting Affordable Housing, as set forth in subpart D of this part, to the extent the Affordable Housing was financed by the CMF Award. For the purposes of meeting the 10-year affordability period requirement, Recipients are not required to track Affordable Housing that was financed by sources other than the CMF Award.
The Recipient must use its CMF Award to finance and support Affordable Housing Activities and/or Economic Development Activities through the following eligible activities:
(a) To capitalize Loan Loss Reserves;
(b) To capitalize a Revolving Loan Fund;
(c) To capitalize an Affordable Housing Fund;
(d) To capitalize a fund to support Economic Development Activities;
(e) To make Risk-Sharing Loans; and
(f) To provide Loan Guarantees.
(a) The Recipient may not use its CMF Award for the following:
(1) Political activities;
(2) Advocacy;
(3) Lobbying, whether directly or through other parties;
(4) Counseling services (including homebuyer or financial counseling);
(5) Travel expenses;
(6) Preparing or providing advice on tax returns;
(7) Emergency shelters (including shelters for disaster victims);
(8) Nursing homes;
(9) Convalescent homes;
(10) Residential treatment facilities;
(11) Correctional facilities; or
(12) Student dormitories.
(b) The Recipient shall not use the CMF Award to finance or support Projects that include:
(1) The operation of any private or commercial golf course, country club, massage parlor, hot tub facility, suntan facility, racetrack or other facility used for gambling, or any store the principal business of which is the sale of alcoholic beverages for consumption off premises; or
(2) Farming activities (within the meaning of Internal Revenue Code (IRC) section 2032A(e)(5)(A) or (B)), if, as of the close of the taxable year of the
(c) In any given application round, no more than 30 percent of a CMF Award may be used for Economic Development Activities.
(d) Any Recipient that uses its CMF Award for a Loan Guarantee or Loan Loss Reserves must ensure the underlying loan(s) are made to support Affordable Housing Activities and Economic Development Activities. The Affordable Housing resulting from the Recipient's Loan Guarantee or Loan Loss Reserve shall be tracked for 10 years, as set forth in subpart D of this part.
(e) If loans that are made pursuant to a Loan Guarantee or Loan Loss Reserves are repaid during the Investment Period, the Recipient must use the repaid funds for Loan Guarantees or Loan Loss Reserves targeted to the income population (Extremely Low-Income, Very Low-Income, Low-Income) set forth in the Recipient's Assistance Agreement, for the duration of the Investment Period.
(f) The Recipient may not use more than five (5) percent of its CMF Award for Direct Administrative Expenses.
(a) Program Income earned in the form of principal and equity repayments must be used by the Recipient for the approved, eligible CMF Award uses as further set forth in the Assistance Agreement for the duration of the Investment Period.
(b) Program Income earned in the form of interest payments, and all other forms of Program Income (except for that which is earned as described in paragraph (a) of this section, must be used by the Recipient as set forth in the Assistance Agreement and in accordance with 2 CFR part 1000.
Each Recipient that uses its CMF Award for Affordable Housing Activities must ensure that 100 percent of Eligible Project Costs are attributable to Affordable Housing; meaning, that they comply with the affordability qualifications set forth in this subpart for Eligible-Income Families. Further, as a subset of said 100 percent, greater than 50 percent of the Eligible Project Costs must be attributable to Affordable Housing that comply with the affordability qualifications set forth in this subpart for Low-Income, Very Low-Income, or Extremely Low-Income Families, or as further set forth in the applicable NOFA and/or Assistance Agreement.
To qualify as Affordable Housing, each rental Multi-family housing Project financed with CMF Award must have at least 20 percent of the units occupied by any combination of Low-Income, Very Low-Income, or Extremely Low-Income Families and must comply with the rent limits set forth herein. However, the CDFI Fund may require a greater percentage of the units per Project to be income-targeted and/or require a specific targeted income commitment in any given application round, as set forth in the NOFA and Assistance Agreement for that application round.
(a)
(1) For an Eligible-Income Family, 30 percent of the annual income of a Family whose annual income equals 120 percent of the area median income, with adjustments for number of bedrooms in the unit, as set forth in IRC section 42(g)(2).
(2) For a Low-Income Family, 30 percent of the annual income of a Family whose annual income equals 80 percent of the area median income, with adjustments for number of bedrooms in the unit, as set forth in IRC section 42(g)(2). If the unit or tenant receives Federal or State rental subsidy, and the Family pays as a contribution towards rent not more than 30 percent of the Family's income, the maximum rent (
(3) For a Very Low-Income Family, 30 percent of the annual income of a Family whose annual income equals 50 percent of the area median income, with adjustments for number of bedrooms in the unit as described in paragraph (a) of this section. If the unit or tenant receives Federal or State rental subsidy, and the Family pays as a contribution towards rent not more than 30 percent of the Family's income, the maximum rent (
(4) For an Extremely Low-Income Family, 30 percent of the annual income of a Family whose annual income equals 30 percent of the area median income, with adjustments for number of bedrooms in the unit as described in paragraph (a) of this section. If the unit or tenant receives Federal or State rental subsidy, and the Family pays as a contribution toward rent not more than 30 percent of the Family's income, the maximum rent (
(b)
(c)
(d)
(e)
(f)
(2) One of the following two definitions of “annual income” must be used to determine whether a Family is income-eligible:
(i) Adjusted gross income as defined for purposes of reporting under Internal Revenue Service (IRS) Form 1040 series for individual Federal annual income tax purposes; or
(ii) “Annual Income” as defined at 24 CFR 5.609 (except that when determining the income of a homeowner for an owner-occupied Rehabilitation Project, the value of the homeowner's principal residence may be excluded from the calculation of Net Family Assets, as defined in 24 CFR 5.603).
(3) Although either of the above two definitions of “annual income” is permitted, in order to calculate adjusted income, exclusions from income set forth at 24 CFR 5.611 shall be applied.
(4) The CDFI Fund reserves the right to deem certain government programs, under which a Low-Income Family is a recipient, as income eligible for purposes of meeting the tenant income requirements under this section.
(g)
(2) Tenants whose incomes no longer qualify must pay rent no greater than the lesser of the amount payable by the tenant under State or local law or 30 percent of the Family's annual income, except if the gross rent of a unit is subject to the restrictions in IRC section 42(g)(2) or the restrictions in an extended low-income housing commitment under IRC section 42(h)(6), then the tenants of that unit must pay rent governed by those restrictions. Tenants who no longer qualify as Eligible-Income are not required to pay rent in excess of the market rent for comparable, unassisted units in the neighborhood.
(3) If the income of a tenant of a CMF-financed or assisted unit no longer qualifies, the Recipient may designate another unit, within the CMF-financed or assisted Project, as a replacement unit that meets the affordability qualifications for the same income category as the original unit, as further set forth in the Recipient's Assistance Agreement. If there is not an available replacement unit, the Recipient must fill the first available vacancy with a tenant that meets the affordability qualifications for the same income category of the original unit as necessary to maintain compliance with the CMF requirements and the Assistance Agreement.
(a)
(1) The Housing must be Single-family housing.
(2) The Single-family housing price does not exceed 95 percent of the median purchase price for the area as used in the HOME Program and as determined by HUD and the applicable Participating Jurisdiction.
(3) The Single-family housing must be purchased by a qualifying Family as set forth in § 1807.400. The Single-family housing must be the principal residence of the Family throughout the period described in paragraph (a)(4) of this section.
(4)
(5)
(b)
(1) The estimated value of the Single-family housing, after Rehabilitation,
(2) The Single-family housing is the principal residence of a qualifying Family as set forth in § 1807.400, at the time that the CMF Award is Committed to the Single-family housing.
(3) Single-family housing under this paragraph (b) must meet the affordability requirements for at least 10 years after Rehabilitation is completed or meet the resale provisions of paragraph (a)(5) of this section.
(c)
(d)
(e)
(a) Each CMF Award must result in Eligible Project Costs in an amount that equals at least 10 times the amount of the CMF Award or some higher standard established by the CDFI Fund in the Recipient's Assistance Agreement. Such Eligible Project Costs must be for Affordable Housing Activities and Economic Development Activities, as set forth in the Assistance Agreement.
(b)
(2) The Recipient must report to the CDFI Fund all Leveraged Costs, with the following limitations:
(i) No costs attributable to prohibited uses as set forth in § 1807.302(a) and (b) may be reported as Leveraged Costs;
(ii) All Leveraged Costs attributable to Affordable Housing Activities must be for Affordable Housing, as set forth in § 1807.401 or § 1807.402, and as further described in the Assistance Agreement;
(iii) All eligible Leveraged Costs attributable to Economic Development Activities shall be described in the Assistance Agreement.
(c) Recipients must report Leveraged Costs information through forms or electronic systems provided by the CDFI Fund. Consequently, Recipients must maintain appropriate documentation, such as audited financial statements, wire transfers documents, pro-formas, and other relevant records, to support such reports.
(a) The CMF Award must be Committed by the Recipient for use by the date designated in its Assistance Agreement.
(b) The Recipient must evidence such commitment with a written, legally binding agreement to provide CMF Award proceeds to the qualifying Family, developer or project sponsor for a Project whose:
(1) Construction can reasonably be expected to start within 12 months of the commitment agreement date;
(2) Property title will be transferred within 6 months of the commitment agreement date; or
(3) Construction schedule ensures Project Completion within 5 years of a date specified in the Assistance Agreement.
(c) The CDFI Fund will make Payment of CMF Award based on a deployment schedule contained in the CMF Award application, in addition to any other documentation and/or forms that the CDFI Fund may require.
(d) Upon receipt of CMF Award, the Recipient must make an initial disbursement of said CMF Award by the date designated in its Assistance Agreement. The CDFI Fund may make Payment of CMF Award in a lump sum or other manner, as determined appropriate by the CDFI Fund. The CDFI Fund will not provide any Payment until the Recipient has satisfied all conditions set forth in the applicable NOFA and Assistance Agreement.
An eligible Applicant and its Subsidiaries and Affiliates may not be awarded more than 15 percent of the aggregate funds available for CMF Awards during any year.
(a) Upon Project Completion, the Project must be placed into service by the date designated in the Assistance Agreement. Project Completion occurs, as determined by the CDFI Fund, when:
(1) All necessary title transfer requirements and construction work have been performed;
(2) The property standards of paragraph (b) of this section have been met; and
(3) The final drawdown of the CMF Award has been made to the project sponsor or developer;
(4) When a CMF Award is used for Preservation, Project Completion occurs when the refinance and/or Rehabilitation is completed in addition to the requirements set forth in this paragraph (a).
(b) By the Project Completion date, the Project must meet the requirements of this part, including the following property standards (which must be met for a period of at least 10 years after the Project Completion date):
(1) Projects that are constructed or Rehabilitated with a CMF Award must meet all applicable State and local codes, Rehabilitation standards, ordinances, and zoning requirements at the time of Project Completion or, in the absence of a State or local building code, the International Residential Code or International Building Code (as applicable) of the International Code Council.
(2) In addition, Projects must meet the following requirements:
(i)
(ii)
(iii)
(3)
(i) For rental Housing, if the remaining useful life of one or more major systems is less than the 10-year period of affordability, the Recipient must ensure that, at Project Completion, the developer or Project sponsor establishes a replacement reserve and that monthly payments are made to the reserve that are adequate to repair or replace the systems as needed. Major systems include: Structural support; roofing; cladding and weatherproofing (
(ii) For Homeownership Single-family housing, the Recipient must ensure that, at Project Completion, the Housing is decent, safe, sanitary, and in good repair. The Recipient must ensure that timely corrective and remedial actions are taken by the Project owner to address identified life threatening deficiencies.
(4)
The Recipient shall develop and maintain an internal tracking and reporting system that ensures that the CMF Award is used in accordance with this part and the Assistance Agreement.
The Uniform Administrative Requirements apply to all CMF Awards.
CMF Awards are Federal financial assistance with regard to the application of Federal civil rights laws. CMF Award funds retain their Federal character until the end of the Investment Period.
Each Applicant must submit a CMF Award application in accordance with the applicable Notice of Funds Availability (NOFA) published in the
Each Applicant will be evaluated and selected, at the sole discretion of the CDFI Fund, to receive a CMF Award based on a review process that will include a paper or electronic application, and may include an interview(s) and/or site visit(s), and that is intended to:
(a) Ensure that Applicants are evaluated on a merit basis and in a fair and consistent manner;
(b) Ensure that each Recipient can successfully meet its leveraging goals and achieve Affordable Housing Activity and Economic Development Activity impacts;
(c) Ensure that Recipients represent a geographically diverse group of Applicants serving Metropolitan Areas and Underserved Rural Areas across the United States that meet criteria of economic distress, which may include:
(1) The percentage of Low-Income Families or the extent of poverty;
(2) The rate of unemployment or underemployment;
(3) The extent of disinvestment;
(4) Economic Development Activities that target Extremely Low-Income, Very Low-Income, and Low-Income Families within the Recipient's Service Area; and
(5) Any other criteria the CDFI Fund shall set forth in the applicable NOFA; and
(d) Take into consideration other factors as set forth in the applicable NOFA.
(a)
(b)
(1) The Applicant's ability to use a CMF Award to generate additional investments, including private sources of funding;
(2) The need for affordable housing in the Applicant's Service Area;
(3) The ability of the Applicant to obligate amounts and undertake activities in a timely manner; and
(4) In the case of an Applicant that has previously received assistance under any CDFI Fund program, the Applicant's level of success in meeting its performance goals, reporting requirements, and other requirements contained in the previously negotiated and executed assistance, allocation or award agreement(s) with the CDFI Fund, any undisbursed balance of assistance, and compliance with applicable Federal laws.
(c) The CDFI Fund may consider any other factors that it deems appropriate in reviewing an application, as set forth in the applicable NOFA, the application and related guidance materials.
(d)
(e)
(a) Each Applicant that is selected to receive a CMF Award must enter into an Assistance Agreement with the CDFI
(1) The amount of the CMF Award;
(2) The approved uses of the CMF Award;
(3) The approved Service Area;
(4) The time period by which the CMF Award proceeds must be Committed;
(5) The required documentation to evidence Project Completion; and
(6) Performance goals that have been established by the CDFI Fund pursuant to this part, the NOFA, and the Recipient's application.
(b) The Assistance Agreement shall provide that, in the event of fraud, mismanagement, noncompliance with the Act or these regulations, or noncompliance with the terms and conditions of the Assistance Agreement, on the part of the Recipient, the CDFI Fund, in its discretion, may make a determination to:
(1) Require changes in the performance goals set forth in the Assistance Agreement;
(2) Revoke approval of the Recipient's application;
(3) Reduce or terminate the CMF Award;
(4) Require repayment of any CMF Award that have been paid to the Recipient;
(5) Bar the Recipient from applying for any assistance from the CDFI Fund; or
(6) Take such other actions as the CDFI Fund deems appropriate or as set forth in the Assistance Agreement.
(c) Prior to making a determination that the Recipient has failed to comply substantially with the Act or these regulations or an Assistance Agreement, the CDFI Fund shall provide the Recipient with reasonable notice and opportunity for hearing.
CMF Awards provided pursuant to this part may be provided in a lump sum payment or in some other manner, as determined appropriate by the CDFI Fund. The CDFI Fund shall not provide any Payment under this part until a Recipient has satisfied all conditions set forth in the applicable NOFA and Assistance Agreement.
(a)
(1) Disclose the manner in which the CMF Award is used, including providing documentation to demonstrate Project Completion;
(2) Demonstrate compliance with the requirements of this part and the Assistance Agreement; and
(3) Evaluate the impact of the CMF Award.
(b)
(c)
(d)
(e)
(ii) For-profit Recipients (excluding Insured CDFIs and State-Insured Credit Unions) must submit to the CDFI Fund financial statements audited in conformity with generally accepted auditing standards as promulgated by the American Institute of Certified Public Accountants by a time set forth in the applicable NOFA or Assistance Agreement.
(iii) Insured CDFIs are not required to submit financial statements to the CDFI Fund. The CDFI Fund will obtain the necessary information from publicly available sources. State-Insured Credit Unions must submit to the CDFI Fund copies of the financial statements that they submit to the Appropriate State Agency.
(2)
(ii) The CDFI Fund will use the annual report to collect data to assess the Recipient's compliance with its performance goals and the impact of the CMF and the CDFI industry.
(iii) The Recipient is responsible for the timely and complete submission of the annual report, even if all or a portion of the documents actually are completed by another entity. If such other entities are required to provide information for the annual report, or such other documentation that the CDFI Fund might require, the Recipient is responsible for ensuring that the information is submitted timely and complete. The CDFI Fund reserves the right to contact such other entities and require that additional information and documentation be provided.
(iv) The CDFI Fund's review of the compliance of an Insured CDFI, a Depository Institution Holding Company or a State-Insured Credit Union with the terms and conditions of its Assistance Agreement may also include information from the Appropriate Federal Banking Agency or
(f)
In carrying out its responsibilities pursuant to an Assistance Agreement, the Recipient shall comply with all applicable Federal, State, and local laws, regulations, and ordinances, Uniform Administrative Requirements, and Executive Orders. Furthermore, Recipients must comply with the CDFI Fund's environmental quality regulations (12 CFR part 1815) as well as all other Federal environmental requirements applicable to Federal awards.
No CMF Award may be expended by a Recipient to pay any person to influence or attempt to influence any agency, elected official, officer or employee of a State or local government in connection with the making, award, extension, continuation, renewal, amendment, or modification of any State or local government contract, grant, loan or cooperative agreement as such terms are defined in 31 U.S.C. 1352.
The criminal provisions of 18 U.S.C. 657 regarding embezzlement or misappropriation of funds are applicable to all Recipients and insiders.
The CDFI Fund shall not be deemed to control a Recipient by reason of any CMF Award provided under the Act for the purpose of any applicable law.
The liability of the CDFI Fund and the United States Government arising out of any CMF Award shall be limited to the amount of the CMF Award. The CDFI Fund shall be exempt from any assessments and other liabilities that may be imposed on controlling or principal shareholders by any Federal law or the law of any State. Nothing in this section shall affect the application of any Federal tax law.
Any person who becomes aware of the existence or apparent existence of fraud, waste or abuse of a CMF Award should report such incidences to the Office of Inspector General of the U.S. Department of the Treasury.
Federal Aviation Administration (FAA), DOT.
Final rule.
This action amends the legal description of the Class E surface area airspace and Class E airspace designated as an extension at Alpena County Regional Airport, Alpena, MI, and Muskegon County Airport, Muskegon, MI, eliminating the Notice to Airmen (NOTAM) part-time status, and updates the geographic coordinates of Muskegon County Airport, to coincide with the FAA's aeronautical database.
Effective 0901 UTC, March 31, 2016. The Director of the Federal Register approves this incorporation by reference action under Title 1, Code of Federal Regulations, part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments.
FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at
FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.
Jeffrey Claypool, Federal Aviation Administration, Operations Support Group, Central Service Center, 10101 Hillwood Parkway, Fort Worth, TX 76177; telephone (817) 222-5711.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it amends controlled airspace at Alpena County Regional Airport, Alpena, MI, and Muskegon County Airport, Muskegon, MI.
In a review of the airspace, the FAA found the airspace for Alpena County Regional Airport, Alpena, MI, and Muskegon County Airport, Muskegon, MI, as published in FAA Order 7400.9Z, Airspace Designations and Reporting Points, does not require part time status. This is an administrative change removing the part time NOTAM information from the legal descriptions for the above airports.
Class E airspace designations are published in paragraph 6002 and 6004, respectively, of FAA Order 7400.9Z dated August 6, 2015, and effective September 15, 2015, which is incorporated by reference in 14 CFR part 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.
This document amends FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, and effective September 15, 2015. FAA Order 7400.9Z is publicly available as listed in the
This action amends Title 14, Code of Federal Regulations (14 CFR) part 71 by eliminating the NOTAM information that reads, “This Class E airspace is effective during the specific dates and times established in advance by a Notice to Airmen. The effective date and time will thereafter be continuously published in the Airport/Facility Directory.” from the regulatory text of the Class E surface area airspace and Class E airspace designated as an extension to Class D, at Alpena County Regional Airport, Alpena, MI, and Muskegon County Airport, Muskegon, MI. Additionally, the geographic coordinates of the Muskegon County Airport are being updated to coincide with the FAA's aeronautical database.
This is an administrative change amending the description for the above Michigan airports to be in concert with the FAA's aeronautical database, and does not affect the boundaries, or operating requirements of the airspace; therefore, notice and public procedure under 5 U.S.C. 553(b) are unnecessary.
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current, is non-controversial and unlikely to result in adverse or negative comments. It, therefore: (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that only affects air traffic procedures and air navigation, it is certified that this rule, when promulgated, does not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA has determined that this action qualifies for categorical exclusion under the National Environmental Policy Act in accordance with FAA Order 1050.1F, “Environmental Impacts: Policies and Procedures,” paragraph 5-6.5.a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exist that warrant preparation of an environmental assessment.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
Within a 4.4-mile radius of the Alpena County Regional Airport, and within 2.5 miles each side of the Alpena VORTAC 350° radial, extending from the 4.4-mile radius of the airport to 7 miles north of the VORTAC, and within 2.5 miles each side of the Alpena VORTAC 187° radial, extending from the 4.4-mile radius of the airport to 7 miles south of the VORTAC.
Within a 4.2-mile radius of the Muskegon County Airport and within 1.3 miles each side of the Muskegon VORTAC 271° radial extending from the VORTAC to the 4.2-mile radius of Muskegon County Airport.
That airspace extending upward from the surface within 2.5 miles each side of the Alpena VORTAC 350° radial, extending from the 4.4-mile radius of Alpena County Regional Airport to 7 miles north of the VORTAC, and within 2.5 miles each side of the Alpena VORTAC 187° radial, extending from the 4.4-mile radius of the airport to 7 miles south of the VORTAC.
That airspace extending upward from the surface within 1.3 miles each side of the Muskegon VORTAC 271° radial extending from the VORTAC to the 4.2-mile radius of the Muskegon County Airport.
Federal Aviation Administration (FAA), DOT.
Final rule.
This action amends the legal description of the Class E surface area airspace and Class E airspace designated as an extension, at Rochester International Airport, Rochester, MN, and St. Cloud Regional Airport, St. Cloud, MN, eliminating the Notice to Airmen (NOTAM) part-time status. This action also updates the geographic coordinates of Rochester International Airport to coincide with the FAA's aeronautical database.
Effective 0901 UTC, March 31, 2016. The Director of the Federal Register approves this incorporation by reference action under Title 1, Code of Federal Regulations, part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments.
FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at
FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.
Jeffrey Claypool, Federal Aviation Administration, Operations Support Group, Central Service Center, 10101 Hillwood Parkway, Fort Worth, TX 76177; telephone (817) 222-5711.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it amends controlled airspace at Rochester International Airport, Rochester, MN and St. Cloud Regional Airport, St. Cloud, MN.
In a review of the airspace, the FAA found the Class E surface airspace and Class E airspace designated as an extension, for Rochester International Airport, Rochester, MN, and St. Cloud Regional Airport, St. Cloud, MN, as published in FAA Order 7400.9Z, Airspace Designations and Reporting Points, does not require part time status. This is an administrative change removing the part time NOTAM information from the legal descriptions for the above airports.
Class E airspace designations are published in paragraph 6002 and 6004 of FAA Order 7400.9Z dated August 6, 2015, and effective September 15, 2015, which is incorporated by reference in 14 CFR part 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.
This document amends FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, and effective September 15, 2015. FAA Order 7400.9Z is publicly available as listed in the
This action amends Title 14, Code of Federal Regulations (14 CFR) part 71 by eliminating the NOTAM information that reads, “This Class E airspace is effective during the specific dates and times established in advance by a Notice to Airmen. The effective date and time will thereafter be continuously published in the Airport/Facility Directory.” from the regulatory text of Class E surface area airspace and Class E airspace designated as an extension to Class D, at Rochester International Airport, Rochester, MN, and St. Cloud Regional Airport, St. Cloud, MN. Additionally, the geographic coordinates of the Rochester International Airport are being updated to coincide with the FAA's aeronautical database.
This is an administrative change amending the description for the above Minnesota airports to be in concert with the FAA's aeronautical database, and does not affect the boundaries, or operating requirements of the airspace; therefore, notice and public procedure under 5 U.S.C. 553(b) are unnecessary.
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current, is non-controversial and unlikely to result in adverse or negative comments. It, therefore: (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that only affects air traffic procedures and air navigation, it is certified that this rule, when promulgated, does not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA has determined that this action qualifies for categorical exclusion under the National Environmental Policy Act in accordance with FAA Order 1050.1F, “Environmental Impacts: Policies and Procedures,” paragraph 5-6.5.a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exist that warrant preparation of an environmental assessment.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
Within a 4.3-mile radius of Rochester International Airport, and within 3.1 miles each side of the Rochester VOR/DME 028° radial, extending from the 4.3-mile radius to 7 miles southwest of the airport.
Within a 4.1-mile radius of St. Cloud Regional Airport and within 2.4 miles each side of the St. Cloud VOR/DME 143° radial, extending from the 4.1-mile radius to 7.2 miles southeast of the airport.
That airspace extending upward from the surface within 3.1 miles each side of Rochester VOR/DME 028° radial, extending from the 4.3-mile radius to 7 miles southwest of the airport.
That airspace extending upward from the surface within 2.4 miles each side of St. Cloud VOR/DME 143° radial extending from the 4.1-mile radius of St. Cloud Regional Airport to 7.2 miles southeast of the airport.
Federal Aviation Administration (FAA), DOT.
Final rule.
This action amends the legal description of Class E surface area airspace and Class E airspace designated as an extension at Wilmington Air Park, Wilmington, OH, eliminating the Notice to Airmen (NOTAM) part-time status. This action also updates the airport name of Wilmington Air Park, Wilmington, OH, to coincide with the FAA's aeronautical database.
Effective 0901 UTC, March 31, 2016. The Director of the Federal Register approves this incorporation by reference action under Title 1, Code of Federal Regulations, part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments.
FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at
FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.
Jeffrey Claypool, Federal Aviation Administration, Operations Support Group, Central Service Center, 10101 Hillwood Parkway, Fort Worth, TX 76177; telephone (817) 222-5711.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it amends controlled airspace at Wilmington Air Park, Wilmington, OH.
In a review of the airspace, the FAA found the airspace for Wilmington Air Park, Wilmington, OH, as published in FAA Order 7400.9Z, Airspace Designations and Reporting Points, does not require part time status. This is an administrative change removing the part time NOTAM information from the legal description for the airport.
Class E airspace designations are published in paragraph 6002 and 6004, respectively, of FAA Order 7400.9Z dated August 6, 2015, and effective September 15, 2015, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.
This document amends FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, and effective September 15, 2015. FAA Order 7400.9Z is publicly available as listed in the
This action amends Title 14, Code of Federal Regulations (14 CFR) part 71 by eliminating the NOTAM information that reads, “This Class E airspace is effective during the specific dates and times established in advance by a Notice to Airmen. The effective date and time will thereafter be continuously published in the Airport/Facility Directory.” from the regulatory text of the Class E surface area airspace, and Class E airspace designated as an extension to Class D, at Wilmington Air Park, Wilmington, OH, formerly Airborne Airpark.
This is an administrative change amending the description for Wilmington Air Park to be in concert with the FAA's aeronautical database, and does not affect the boundaries, or operating requirements of the airspace; therefore, notice and public procedure under 5 U.S.C. 553(b) are unnecessary.
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current, is non-controversial and unlikely to result in adverse or negative comments. It, therefore: (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that only affects air traffic procedures and air navigation, it is certified that this rule, when promulgated, does not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA has determined that this action qualifies for categorical exclusion under the National Environmental Policy Act in accordance with FAA
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
Within a 4.2-mile radius of Wilmington Air Park, and within 3.7 miles each side of the Midwest VOR/DME 215° radial extending from the 4.2-mile radius of Wilmington Air Park to 7 miles southwest of the airport, and within 3.7 miles each side of the Midwest VOR/DME 041° radial extending from the 4.2-mile radius of the airport to 7 miles northeast of the airport, excluding that portion of airspace within a 1-mile radius of Hollister Field Airport.
That airspace extending upward from the surface within 3.7 miles each side of the Midwest VOR/DME 215° radial, extending from the 4.2-mile radius of Wilmington Air Park to 7 miles southwest of the airport, and within 3.7 miles each side of the Midwest VOR/DME 041° radial extending from the 4.2-mile radius of the airport to 7 miles northeast of the airport, excluding that portion of airspace within a 1-mile radius of Hollister Field Airport.
Drug Enforcement Administration, Department of Justice.
Final rule.
This final rule adopts the interim final rule, with a correction to spelling of the manufacturer's name that was published in the
This final rule is effective on February 8, 2016.
Barbara J. Boockholdt, Office of Diversion Control, Drug Enforcement Administration; Mailing Address: 8701 Morrissette Drive, Springfield, Virginia 22152; Telephone: (202) 598-6812.
The Drug Enforcement Administration (DEA) implements and enforces titles II and III of the Comprehensive Drug Abuse Prevention and Control Act of 1970, as amended. 21 U.S.C. 801-971. Titles II and III are referred to as the “Controlled Substances Act” and the “Controlled Substances Import and Export Act,” respectively, and they are collectively referred to as the “Controlled Substances Act” or the “CSA” for the purpose of this action. The DEA publishes the implementing regulations for these statutes in title 21 of the Code of Federal Regulations (CFR), chapter II.
The CSA and its implementing regulations are designed to prevent, detect, and eliminate the diversion of controlled substances and listed chemicals into the illicit market while ensuring an adequate supply is available for the legitimate medical, scientific, research, and industrial needs of the United States. Controlled substances have the potential for abuse and dependence and are controlled to protect the public health and safety.
Under the CSA, each controlled substance is classified into one of five schedules based upon its potential for abuse, its currently accepted medical use in treatment in the United States, and the degree of dependence the drug or other substance may cause. 21 U.S.C. 812. The initial schedules of controlled substances established by Congress are found at 21 U.S.C. 812(c) and the current list of all scheduled substances is published at 21 CFR part 1308.
The CSA states that the Attorney General shall by regulation exclude any nonnarcotic drug which contains a controlled substance from the application of the CSA, if such drug may, under the Federal Food, Drug, and Cosmetic Act (FD&C Act), 21 U.S.C. 301
This final rule adopts, with a change to the spelling of the manufacturer's name, the interim final rule, “Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products: Vicks® VapoInhaler® ” that was published in the
On February 9, 2012, pursuant to the application process of § 1308.21, the DEA received correspondence from The Procter & Gamble Company (“P&G”) notifying the DEA that it had reduced the quantity of
Based on the application and other information received, including the quantitative composition of the substance and labeling and packaging information, the DEA determined that this product may, under the FD&C Act, be lawfully sold over-the-counter without a prescription. 21 U.S.C. 811(g)(1). In addition, the Deputy Assistant Administrator of the Office of Diversion Control found that the active ingredient in this drug product (levmetamfetamine) is a schedule II controlled substance and is not a narcotic drug as defined by 21 U.S.C. 802(17). The Deputy Assistant Administrator of the Office of Diversion Control therefore found and concluded that this product continues to meet the criteria for exclusion from the CSA pursuant to 21 U.S.C. 811(g)(1).
The interim final rule provided an opportunity for interested persons to submit written comments on the rule on or before December 28, 2015. The DEA received one comment in response to the publication of the interim final rule which was a request from P&G for a correction to the spelling of their name. As noted above, the spelling has been corrected in this final rule.
This exclusion only applies to the finished drug product in the form of an inhaler (in the exact formulation detailed in the application for exclusion), which is lawfully sold over-the-counter without a prescription under the FD&C Act. The extraction or removal of the active ingredient (levmetamfetamine) from the inhaler shall negate this exclusion and result in the possession of a schedule II controlled substance.
This regulation has been developed in accordance with the Executive Orders 12866, “Regulatory Planning and Review,” section 1(b) and Executive Order 13563, “Improving Regulation and Regulatory Review.” The DEA has determined that this rule is not “a significant regulatory action,” and accordingly this rule has not been reviewed by the Office of Management and Budget. As discussed above, this product was previously exempted under a different company name. As discussed in the interim final rule, this action will not have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities; create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in Executive Order 12866.
The Regulatory Flexibility Act (RFA) (5 U.S.C. 601-612) applies to rules that are subject to notice and comment. The DEA determined, as explained in the interim final rule, that public notice and comment were impracticable and contrary to the public interest. Consequently, the RFA does not apply. Although the RFA does not apply to this rulemaking, the DEA has reviewed the potential impacts of this final rule and determined that it will not have a significant economic impact on a substantial number of small entities. As discussed above and in the interim final rule, this product was previously exempted under a different company name. The Deputy Assistant Administrator, in accordance with the Regulatory Flexibility Act, has reviewed this regulation and by approving it certifies that this regulation will not have a significant economic impact on a substantial number of small entities.
This regulation meets the applicable standards set forth in sections 3(a) and 3(b)(2) of Executive Order 12988, “Civil Justice Reform,” to eliminate drafting errors and ambiguity, minimize litigation, provide a clear legal standard for affected conduct, and promote simplification and burden reduction.
This rulemaking does not have federalism implications warranting the application of Executive Order 13132. The rule does not have substantial direct effects on the States, on the relationship between the Federal Government and the States, or the distribution of power and responsibilities among the various levels of government.
This rule does not have tribal implications warranting the application of Executive Order 13175. This rule does not 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.
As stated in the interim final rule, the DEA has determined and certifies pursuant to the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1501
As stated in the interim final rule, this rule does not impose a new collection of information requirement under the Paperwork Reduction Act, 44 U.S.C. 3501-3521. This action would not impose recordkeeping or reporting requirements on State or local governments, individuals, businesses, or organizations. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
This rule is not a major rule as defined by section 804 of the Small Business Regulatory Enforcement Fairness Act of 1996 (Congressional Review Act (CRA)). This rule will not result in: An annual effect on the economy of $100,000,000 or more; a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions; or significant adverse effects on competition, employment, investment, productivity, innovation, or on the ability of United States-based companies to compete with foreign-based companies in domestic and export markets.
Administrative practice and procedure, Drug traffic control, Reporting and recordkeeping requirements.
Accordingly, for the reasons stated above, the interim final rule that was published in the
21 U.S.C. 811, 812, 871(b), unless otherwise noted.
Drug Enforcement Administration, Department of Justice.
Final rule.
This final rule adopts, without change, the interim final rule that was published in the
This final rule is effective on February 8, 2016.
Barbara J. Boockholdt, Office of Diversion Control, Drug Enforcement Administration; Mailing Address: 8701 Morrissette Drive, Springfield, Virginia 22152; Telephone: (202) 598-6812.
The Drug Enforcement Administration (DEA) implements and enforces titles II and III of the Comprehensive Drug Abuse Prevention and Control Act of 1970, as amended. 21 U.S.C. 801-971. Titles II and III are referred to as the “Controlled Substances Act” and the “Controlled Substances Import and Export Act,” respectively, and they are collectively referred to as the “Controlled Substances Act” or the “CSA” for the purpose of this action. The DEA publishes the implementing regulations for these statutes in title 21 of the Code of Federal Regulations (CFR), chapter II.
The CSA and its implementing regulations are designed to prevent, detect, and eliminate the diversion of controlled substances and listed chemicals into the illicit market while ensuring an adequate supply is available for the legitimate medical, scientific, research, and industrial needs of the United States. Controlled substances have the potential for abuse and dependence and are controlled to protect the public health and safety.
Under the CSA, each controlled substance is classified into one of five schedules based upon its potential for abuse, its currently accepted medical use in treatment in the United States, and the degree of dependence the drug or other substance may cause. 21 U.S.C. 812. The initial schedules of controlled substances established by Congress are found at 21 U.S.C. 812(c) and the current list of all scheduled substances is published at 21 CFR part 1308.
The CSA states that the Attorney General shall by regulation exclude any nonnarcotic drug which contains a controlled substance from the application of the CSA, if such drug may, under the Federal Food, Drug, and Cosmetic Act (FD&C Act), 21 U.S.C. 301
This final rule adopts, without change, the interim final rule, “Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products: Nasal Decongestant Inhaler/Vapor Inhaler” that was published in the
On December 10, 2013, pursuant to the application process of § 1308.21, the DEA received correspondence from Aphena Pharma Solutions—New York, LLC (Aphena Pharma) stating that it had acquired Classic Pharmaceuticals LLC and requesting that the current exclusion for the drug product Nasal Decongestant Inhaler/Vapor Inhaler be transferred to Aphena Pharma. Aphena Pharma also stated that the manufacturing process (
Based on the application and other information received, the DEA determined that this product may, under the FD&C Act, be lawfully sold over-the-counter without a prescription. 21 U.S.C. 811(g)(1). In addition, the Deputy Assistant Administrator of the Office of Diversion Control found that the active ingredient in this drug product (levmetamfetamine) is a schedule II controlled substance
The interim final rule provided an opportunity for interested persons to
This exclusion only applies to the finished drug product in the form of an inhaler (in the exact formulation detailed in the application for exclusion), which is lawfully sold under the FD&C Act over-the-counter without a prescription. The extraction or removal of the active ingredient (levmetamfetamine) from the inhaler shall negate this exclusion and result in the possession of a schedule II controlled substance.
This regulation has been developed in accordance with the Executive Orders 12866, “Regulatory Planning and Review,” section 1(b) and Executive Order 13563, “Improving Regulation and Regulatory Review.” The DEA has determined that this rule is not a significant regulatory action, and accordingly this rule has not been reviewed by the Office of Management and Budget. As discussed above, this product was previously exempted under a different company name. As discussed in the interim final rule, this action will not have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local or tribal governments or communities; create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in Executive Order 12866.
The Regulatory Flexibility Act (RFA) (5 U.S.C. 601-612) applies to rules that are subject to notice and comment. The DEA determined, as explained in the interim final rule, that public notice and comment were impracticable and contrary to the public interest. Consequently, the RFA does not apply. Although the RFA does not apply to this rulemaking, the DEA has reviewed the potential impacts of this final rule and determined that it will not have a significant economic impact on a substantial number of small entities. As discussed above and in the interim final rule, this product was previously exempted under a different company name. The Deputy Assistant Administrator, in accordance with the RFA, has reviewed this regulation and by approving it certifies that this regulation will not have a significant economic impact on a substantial number of small entities.
This regulation meets the applicable standards set forth in sections 3(a) and 3(b)(2) of Executive Order 12988, “Civil Justice Reform,” to eliminate drafting errors and ambiguity, minimize litigation, provide a clear legal standard for affected conduct, and promote simplification and burden reduction.
This rulemaking does not have federalism implications warranting the application of Executive Order 13132. The rule does not have substantial direct effects on the States, on the relationship between the Federal Government and the States, or the distribution of power and responsibilities among the various levels of government.
This rule does not have tribal implications warranting the application of Executive Order 13175. This rule does not 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 DEA has determined and certifies pursuant to the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1501
This rule does not impose a new collection of information requirement under the Paperwork Reduction Act, 44 U.S.C. 3501-3521. This action would not impose recordkeeping or reporting requirements on State or local governments, individuals, businesses, or organizations. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
This rule is not a major rule as defined by section 804 of the Small Business Regulatory Enforcement Fairness Act of 1996 (Congressional Review Act (CRA)). This rule will not result in: An annual effect on the economy of $100,000,000 or more; a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions; or significant adverse effects on competition, employment, investment, productivity, innovation, or on the ability of United States-based companies to compete with foreign-based companies in domestic and export markets.
Administrative practice and procedure, Drug traffic control, Reporting and recordkeeping requirements.
Accordingly, for the reasons stated above, the interim final rule that was published in the
National Highway Traffic Safety Administration (NHTSA), Department of Transportation (DOT).
Final rule.
NHTSA is amending the side marker requirements contained in the
Petitions for Reconsideration: Petitions for reconsideration of this final rule must be received not later than March 24, 2016.
Any petitions for reconsideration should refer to the docket number of this document and be submitted to: Administrator, National Highway Traffic Safety Administration, 1200 New Jersey Avenue SE., West Building, Ground Floor, Docket Room W12-140, Washington, DC 20590.
For technical issues: Mr. Wayne McKenzie, Office of Crash Avoidance Standards, NHTSA, 1200 New Jersey Avenue SE., West Building, Washington, DC 20590 (Telephone: (202) 366-1729) (Fax: (202) 366-7002).
For legal issues: Mr. John Piazza, Office of the Chief Counsel, NHTSA, 1200 New Jersey Avenue SE., West Building, Washington, DC 20590 (Telephone: (202) 366-2992) (Fax: (202) 366-3820).
Side marker lamps have been required by FMVSS No. 108 since it was promulgated as one of the initial Federal Motor Vehicles Safety Standards in 1967.
Relevant to the present rulemaking is a change that was made to the side marker requirements in 1980 in response to a petition for rulemaking from Chrysler Corporation.
The next change to the side marker requirements relevant to this final rule occurred in 2007, when NHTSA reorganized FMVSS No. 108. The reorganization was intended to streamline the regulatory text and clarify the standard's requirements. That final rule made the standard more user-friendly by significantly reducing the number of third-party documents, such as SAE
However, the newly revised version of FMVSS No. 108 inadvertently changed the alternative compliance option for side marker lamps. Prior to the reorganization, side marker lamps were required to conform to SAE Standard J592e (July 1972) (
Therefore, the agency inadvertently added back into FMVSS No. 108 the same width-based language it had deleted in 1980. This had the effect of substantively changing the side marker requirements by limiting the vehicles that were eligible for the additional compliance option. Before the reorganization, vehicles less than 30 feet long were eligible; after the rewrite, a vehicle had to be both less than 30 feet long
To address this change, NHTSA published a notice of proposed rulemaking (NPRM) on December 4, 2012.
NHTSA received only three comments in response to the 2012 NPRM. The Alliance of Automobile Manufacturers (the “Alliance”) stated that it agrees with NHTSA's analysis of the situation surrounding the changes to FMVSS No. 108 during the administrative reorganization process as well as the proposed revisions. The Alliance stated that the proposed changes would bring the side marker photometry requirements back in line with the original intent of the 1980 final rule and restore the requirements that were in force prior to the 2007 final rule. The Alliance also commented that the phrase “. . . and less than 80 inches (2m) in overall width” should be deleted from footnote 1 of Table X to ensure there is no ambiguity concerning the application of side marker lamp inboard photometry requirements.
General Motors submitted a comment in support of the change to the proposal and stated that the proposed changes would restore the previous requirements and would have no overall effect on safety.
The European Commission submitted a comment requesting an extension of the comment period to February 5, 2013.
NHTSA has carefully considered the comments submitted in this rulemaking. We have reviewed the comments received from GM and the Alliance and agree with the rationale presented. Having received no information to the contrary, we are amending S7.4.13.2 of FMVSS No. 108 to delete the phrase “and less than 2032 mm in overall width,” consistent with the proposal. This revision will restore the photometric requirements in FMVSS No. 108 for side marker lamps on vehicles less than 30 feet in length so that the requirements may be met for all inboard test points at a distance of 15 feet from the vehicle on a vertical plane that is perpendicular to the longitudinal axis of the vehicle and located midway between the front and rear side marker lamps, regardless of the width of the vehicle.
We have also decided to adopt the Alliance's proposed revision to footnote 1 of Table X. The text in the footnote that the Alliance proposes to delete—“and less than 80 inches (2m) in overall width”—is essentially the same as the text we are deleting from S7.4.13.2. Similarly revising this footnote will make the requirements stated in the footnote consistent with the requirements stated in S7.4.13.2.
With respect to the comment from the European Commission, NHTSA chose not to extend the comment period formally because we stated in the NPRM that the agency would consider late comments to the extent practicable. Given that this final rule is being published several years after the NPRM and we did not receive any additional comments or requests to extend the comment period, we consider this comment resolved.
In the NPRM we proposed an effective date of 30 days after publication of the final rule. Under the Safety Act, a FMVSS typically is not effective before the 180th day after the standard is published. We did not receive any comments concerning the proposed effective date. Therefore, in keeping with typical practice, this final rule will be effective August 8, 2016, with optional early compliance. We believe that specifying a later effective date for this final rule will not have any adverse effects or prejudice regulated entities. Moreover, providing for optional early compliance will allow manufacturers to immediately benefit from the flexibility afforded by the revised side marker requirements the same as if the effective date were earlier. NHTSA's compliance policy stated in the 2012 NPRM is terminated as of the effective date of this final rule.
NHTSA has considered the impact of this rulemaking action under Executive Order 12866, Executive Order 13563, and the DOT's regulatory policies and procedures. This final rule was not reviewed by the Office of Management and Budget (OMB) under E.O. 12866, “Regulatory Planning and Review.” It is not considered to be significant under E.O. 12866 or the Department's regulatory policies and procedures.
This final rule restores requirements to the standard that were unintentionally changed during the administrative revision of the standard. Because this final rule merely restores previously existing requirements it is not expected to have any costs. This
The policy statement in section 1 of Executive Order 13609 provides, in part:
The regulatory approaches taken by foreign governments may differ from those taken by U.S. regulatory agencies to address similar issues. In some cases, the differences between the regulatory approaches of U.S. agencies and those of their foreign counterparts might not be necessary and might impair the ability of American businesses to export and compete internationally. In meeting shared challenges involving health, safety, labor, security, environmental, and other issues, international regulatory cooperation can identify approaches that are at least as protective as those that are or would be adopted in the absence of such cooperation. International regulatory cooperation can also reduce, eliminate, or prevent unnecessary differences in regulatory requirements.
NHTSA is not aware of any conflicting regulatory approach taken by a foreign government concerning the subject matter of this rulemaking.
In compliance with the Regulatory Flexibility Act, 5 U.S.C. 60l
NHTSA has examined this rule pursuant to Executive Order 13132 (64 FR 43255, August 10, 1999) and concluded that no additional consultation with States, local governments or their representatives is mandated beyond the rulemaking process. The agency has concluded that the rulemaking would not have sufficient federalism implications to warrant consultation with State and local officials or the preparation of a federalism summary impact statement. The final rule would 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.”
NHTSA rules can preempt in two ways. First, the National Traffic and Motor Vehicle Safety Act contains an express preemption provision: “When a motor vehicle safety standard is in effect under this chapter, a State or a political subdivision of a State may prescribe or continue in effect a standard applicable to the same aspect of performance of a motor vehicle or motor vehicle equipment only if the standard is identical to the standard prescribed under this chapter.” 49 U.S.C. 30103(b)(1). It is this statutory command by Congress that preempts any non-identical State legislative and administrative law addressing the same aspect of performance.
The express preemption provision set forth above is subject to a savings clause under which “[c]ompliance with a motor vehicle safety standard prescribed under this chapter does not exempt a person from liability at common law.” 49 U.S.C. 30103(e). Pursuant to this provision, State common law tort causes of action against motor vehicle manufacturers that might otherwise be preempted by the express preemption provision are generally preserved.
However, the Supreme Court has recognized the possibility, in some instances, of implied preemption of such State common law tort causes of action by virtue of NHTSA's rules, even if not expressly preempted. This second way that NHTSA rules can preempt is dependent upon there being an actual conflict between an FMVSS and the higher standard that would effectively be imposed on motor vehicle manufacturers if someone obtained a State common law tort judgment against the manufacturer, notwithstanding the manufacturer's compliance with the NHTSA standard. Because most NHTSA standards established by an FMVSS are minimum standards, a State common law tort cause of action that seeks to impose a higher standard on motor vehicle manufacturers will generally not be preempted. However, if and when such a conflict does exist—for example, when the standard at issue is both a minimum and a maximum standard—the State common law tort cause of action is impliedly preempted.
Pursuant to Executive Order 13132 and 12988, NHTSA has considered whether this rule could or should preempt State common law causes of action. The agency's ability to announce its conclusion regarding the preemptive effect of one of its rules reduces the likelihood that preemption will be an issue in any subsequent tort litigation.
To this end, the agency has examined the nature (
NHTSA has analyzed this final rule for the purposes of the National Environmental Policy Act. The agency has determined that implementation of this action would not have any significant impact on the quality of the human environment.
Under the procedures established by the Paperwork Reduction Act of 1995, a person is not required to respond to a collection of information by a Federal agency unless the collection displays a valid OMB control number. This final rule would not establish any new information collection requirements.
Under the National Technology Transfer and Advancement Act of 1995 (NTTAA) (Pub. L. 104-113), “all Federal agencies and departments shall use technical standards that are developed or adopted by voluntary consensus standards bodies, using such technical standards as a means to carry out policy objectives or activities determined by the agencies and departments.” This final rule would not adopt or reference any new industry or consensus standards that were not already present in FMVSS No. 108.
With respect to the review of the promulgation of a new regulation, section 3(b) of Executive Order 12988,
Pursuant to this Order, NHTSA notes as follows. The preemptive effect of this final rule is discussed above. NHTSA notes further that there is no requirement that individuals submit a petition for reconsideration or pursue other administrative proceeding before they may file suit in court.
The Unfunded Mandates Reform Act of 1995 requires agencies to prepare a written assessment of the costs, benefits and other effects of proposed or final rules that include a Federal mandate likely to result in the expenditure by State, local or tribal governments, in the aggregate, or by the private sector, of more than $100 million annually (adjusted for inflation with base year of 1995). This final rule would not result in expenditures by State, local or tribal governments, in the aggregate, or by the private sector in excess of $100 million annually.
Executive Order 13211 (66 FR 28355, May 18, 2001) applies to any rulemaking that: (1) Is determined to be economically significant as defined under E.O. 12866, and is likely to have a significantly adverse effect on the supply of, distribution of, or use of energy; or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action. This rulemaking is not subject to E.O. 13211.
The Department of Transportation assigns a regulation identifier number (RIN) to each regulatory action listed in the Unified Agenda of Federal Regulations. The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. You may use the RIN contained in the heading at the beginning of this document to find this action in the Unified Agenda.
Anyone is able to search the electronic form of all comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review DOT's complete Privacy Act Statement in the
Imports, Motor vehicle safety, Motor vehicles, Tires.
In consideration of the foregoing, NHTSA is amending 49 CFR part 571 as set forth below.
49 U.S.C. 322, 30111, 30115, 30117, 30166: delegation of authority at 49 CFR 1.95.
S7.4.13.2
(1) Where a side marker lamp installed on a motor vehicle less than 30 feet in overall length has the lateral angle nearest the other required side marker lamp on the same side of the vehicle reduced from 45° by design as specified by S7.4.13.2, the photometric intensity measurement may be met at the lesser angle.
National Transportation Safety Board (NTSB).
Final rule; confirmation of effective date.
The NTSB publishes confirmation of an amendment to its regulations concerning notification and reporting requirements with regard to aircraft accidents or incidents, titled, “Immediate notification.” The regulation requires reports of Airborne Collision and Avoidance System (ACAS) resolution advisories issued under certain specific circumstances. In a Direct Final Rule published December 15, 2015, the NTSB narrowed the ACAS reporting requirement, consistent with the agency's authority to issue non-controversial amendments to rules. The NTSB also updated its contact information for notifications. This document confirms the changes and the effective date.
The final rule published December 15, 2015 (80 FR 77586) becomes effective February 16, 2016.
A copy of this final rule, published in the
Scott Dunham, National Resource Specialist—ATC, Office of Aviation Safety, (202) 314-6387.
As described in the NTSB's preamble summarizing the direct final rule, in 2010, the NTSB added a requirement for
In collecting such reports since 2010, the NTSB has determined it no longer needs reports of ACAS resolution advisories issued to an aircraft operating in class A airspace. This final rule confirms the NTSB will now only require reports of such resolution advisories when an aircraft operating on an IFR flight plan my comply with the advisory in order to avert a substantial risk of collision between two or more aircraft. As a result, pursuant to its regulations governing rulemaking, the NTSB issued a direct final rule to amend 49 CFR 830.5(a)(10), as described above. 80 FR 77586 (Dec. 15, 2015).
In addition to the removal of a portion of section 830.5(a)(10), the NTSB also amended a footnote that accompanies the first paragraph of section 830.5. The footnote previously contained outdated contact information for NTSB regional offices. The NTSB has updated this footnote to refer the public to
The NTSB's rule on the direct final rulemaking procedure, codified at 49 CFR 800.44, states a direct final rule makes changes to a regulation which will take effect on a certain date unless the NTSB receives an adverse comment or a notice of intent to file an adverse comment.
This final rule is not a significant regulatory action under Executive Order 12866, “Regulatory Planning and Review.” Therefore, Executive Order 12866 does not require a Regulatory Assessment, and the Office of Management and Budget (OMB) has not reviewed this proposed rule under Executive Order 12866.
This rule does not require an analysis under the Unfunded Mandates Reform Act, 2 United States Code (U.S.C.) 1501-1571, or the National Environmental Policy Act, 42 U.S.C. 4321-4347. The NTSB has also analyzed these amendments in accordance with the principles and criteria contained in Executive Order 13132, “Federalism.” This final rule does not contain any regulations that would: (1) Have a substantial direct effect on the states, the relationship between the national government and the states, or the distribution of power and responsibilities among the various levels of government; (2) impose substantial direct compliance costs on state and local governments; or (3) preempt state law. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply.
The NTSB is also aware that the Regulatory Flexibility Act (5 U.S.C. 601
Regarding other Executive Orders and statutory provisions, this final rule also complies with all applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, “Civil Justice Reform,” to minimize litigation, eliminate ambiguity, and reduce burden. In addition, the NTSB has evaluated this rule under: Executive Order 12630, “Governmental Actions and Interference with Constitutionally Protected Property Rights”; Executive Order 13045, “Protection of Children from Environmental Health Risks and Safety Risks”; Executive Order 13175, “Consultation and Coordination with Indian Tribal Governments”; Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use”; and the National Technology Transfer and Advancement Act, 15 U.S.C. 272 note. The NTSB has concluded this rule does not contravene any of the requirements set forth in these Executive Orders or statutes, nor does it prompt further consideration with regard to such requirements.
Aircraft accidents, Aircraft incidents, Aviation safety, Overdue aircraft notification and reporting, Reporting and recordkeeping requirements.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Temporary rule; closure.
NMFS is prohibiting directed fishing with trawl gear, other than pelagic trawl gear for walleye pollock, by American Fisheries Act (AFA) trawl catcher processors in Bycatch Limitation Zone 1 of the Bering Sea and Aleutian Islands management area (BSAI). This action is necessary to prevent exceeding the sideboard limit of the 2016 bycatch allowance of red king crab in Zone 1 specified for AFA trawl catcher processors in the BSAI.
Effective 1200 hrs, Alaska local time (A.l.t.), February 3, 2016, though 2400 hrs, A.l.t., December 31, 2016.
Steve Whitney, 907-586-7269.
NMFS manages the groundfish fishery in the BSAI exclusive economic zone according to the Fishery Management Plan for Groundfish of the Bering Sea and Aleutian Islands Management Area (FMP) prepared by the North Pacific Fishery Management Council under authority of the Magnuson-Stevens Fishery Conservation and Management Act. Regulations governing fishing by U.S. vessels in accordance with the FMP appear at subpart H of 50 CFR part 600 and 50 CFR part 679.
The sideboard limit of the 2016 bycatch allowance of red king crab in Zone 1 specified for the AFA trawl catcher processors in the BSAI is 606 crab as established by the final 2015 and
In accordance with § 679.64(a)(2) and (3), the Administrator, Alaska Region, NMFS (Regional Administrator), has determined that the sideboard limit of red king crab in Zone 1 specified for the AFA catcher processors in the BSAI will be caught. Therefore, NMFS is prohibiting directed fishing with trawl gear in Zone 1, other than pelagic trawl gear for walleye pollock, by AFA trawl catcher processors in the BSAI.
This action responds to the best available information recently obtained from the fishery. The Assistant Administrator for Fisheries, NOAA, (AA), finds good cause to waive the requirement to provide prior notice and opportunity for public comment pursuant to the authority set forth at 5 U.S.C. 553(b)(B) as such requirement is impracticable and contrary to the public interest. This requirement is impracticable and contrary to the public interest as it would prevent NMFS from responding to the most recent fisheries data in a timely fashion and would delay the closure of directed fishing with trawl gear, other than pelagic trawl gear for walleye pollock, by AFA trawl catcher processors in Zone 1 of the BSAI. NMFS was unable to publish a notification providing time for public comment because the most recent, relevant data only became available as of February 1, 2016.
The AA also finds good cause to waive the 30-day delay in the effective date of this action under 5 U.S.C. 553(d)(3). This finding is based upon the reasons provided above for waiver of prior notice and opportunity for public comment.
This action is required by § 679.21 and is exempt from review under Executive Order 12866.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Temporary rule; modification of a closure.
NMFS is opening directed fishing for Pacific cod by catcher/processors using trawl gear in the Western Regulatory Area of the Gulf of Alaska (GOA). This action is necessary to fully use the A season allowance of the 2016 total allowable catch apportioned to catcher/processors using trawl gear in the Western Regulatory Area of the GOA.
Effective 1200 hours, Alaska local time (A.l.t.), February 4, 2016, through 1200 hours, A.l.t., June 10, 2016. Comments must be received at the following address no later than 4:30 p.m., A.l.t., February 23, 2016.
You may submit comments on this document, identified by NOAA-NMFS-2014-0118, by any of the following methods:
•
•
Obren Davis, 907-586-7228.
NMFS manages the groundfish fishery in the GOA exclusive economic zone according to the Fishery Management Plan for Groundfish of the Gulf of Alaska (FMP) prepared by the North Pacific Fishery Management Council under authority of the Magnuson-Stevens Fishery Conservation and Management Act. Regulations governing fishing by U.S. vessels in accordance with the FMP appear at subpart H of 50 CFR part 600 and 50 CFR part 679. Regulations governing sideboard protections for GOA groundfish fisheries appear at subpart B of 50 CFR part 680.
NMFS closed directed fishing for Pacific cod by catcher/processors using trawl gear in the Western Regulatory Area of the GOA under § 679.20(d)(1)(iii) on January 1, 2016 pursuant to the final 2015 and 2016 harvest specifications for groundfish of the Gulf of Alaska (80 FR 10250, February 25, 2015) and inseason adjustment (81 FR 188, January 5, 2016).
NMFS has determined that as of February 1, 2016, approximately 200 metric tons of Pacific cod remain in the A season allowance of the 2016 Pacific cod apportionment for catcher/processors using trawl gear in the Western Regulatory Area of the GOA. Therefore, in accordance with § 679.25(a)(1)(i), (a)(2)(i)(C), and (a)(2)(iii)(D), and to fully use the 2016 total allowable catch (TAC) of Pacific cod in the Western Regulatory Area of the GOA, NMFS is terminating the previous closure and is opening directed fishing for Pacific cod by catcher/processors using trawl gear in the Western Regulatory Area of the GOA. The Administrator, Alaska Region, NMFS, (Regional Administrator) considered the following factors in reaching this decision: (1) The current catch of Pacific cod by catcher/processors using trawl gear in the Western Regulatory Area of the GOA and, (2) the harvest capacity and stated intent on future harvesting patterns of vessels in participating in this fishery.
This action responds to the best available information recently obtained
The AA also finds good cause to waive the 30-day delay in the effective date of this action under 5 U.S.C. 553(d)(3). This finding is based upon the reasons provided above for waiver of prior notice and opportunity for public comment.
Without this inseason adjustment, NMFS could not allow the fishery for Pacific cod by catcher/processors using trawl gear in the Western Regulatory Area of the GOA to be harvested in an expedient manner and in accordance with the regulatory schedule. Under § 679.25(c)(2), interested persons are invited to submit written comments on this action to the above address until February 23, 2016.
This action is required by § 679.25 and is exempt from review under Executive Order 12866.
16 U.S.C. 1801
Office of the Secretary, Interior.
Proposed rule.
This proposed rule establishes the Financial Assistance Interior Regulation (FAIR). The FAIR supplements the OMB
Submit comments on or before April 8, 2016.
You may submit comments on the rulemaking through the Federal eRulemaking Portal at
Mr. James McCaffery, Deputy Director, Office of Acquisition and Property Management, Department of the Interior, 1849 C Street NW., Mail Stop 4262 MIB, Washington, DC 20240; telephone (202) 513-0695; or email
On December 26, 2013, the Office of Management and Budget (OMB) published its
The Omni-Circular required Federal agencies to promulgate regulations implementing the policies and procedures applicable to Federal awards by December 26, 2014. On December 19, 2014, the Department published a final rule to adopt the OMB Omni-Circular in full as 2 CFR 1402, Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards [79 FR 75867]. Subsequently, on December 22, 2014, the Department issued memoranda to supplement the following provisions of the OMB Omni-Circular: (1) Indirect Cost Rates for Federal Financial Assistance Awards and Agreements; (2) Conflict of Interest and Mandatory Disclosures for Financial Assistance; (3) Financial Assistance Application and Merit review Processes; and (4) Financial Assistance Awards for For-Profit Entities, Foreign Public Entities, and Foreign Organizations.
When the Omni-Circular became effective, it superseded many of the Department's existing financial assistance policies. The Department adopted the Omni-Circular in full and has addressed the Department's unique statutory requirements. The Department's adoption of the Omni-Circular is codified at 2 CFR part 1402. The Department intends to add supplemental rules or regulations for financial assistance through the establishment of the Financial Assistance Interior Regulation (FAIR). The FAIR will be codified at 2 CFR part 1403.
Invitation to Comment: This action represents an administrative simplification and is not intended to make any substantive changes to 2 CFR part 200 policies and procedures. In soliciting comments on these actions, the Department therefore is not seeking to revisit substantive issues resolved during the development and finalization of the Omni-Circular.
All Department of the Interior non-regulatory program manuals, handbooks and other materials that are inconsistent with 2 CFR part 200 and 2 CFR parts 1400 and 1402 are superseded, except to the extent that they are (1) required by statute; or (2) authorized in accordance with Omni-Circular Section 200.101,
Except to the extent inconsistent with the regulations in all existing Department of the Interior regulations in 25 CFR parts 23, 27, 39, 40, 41, 256, 272, 278, and 276; 30 CFR parts 725, 735, 884, 886, and 890; 36 CFR parts 60, 61, 63, 65, 67, 72, and 800; 43 CFR parts 26 and 32; and 50 CFR parts 80, 81, 82, 83, and 401 are not superseded by these regulations; nor are any information collection approvals for financial assistance forms that have been granted under the Paperwork Reduction Act.
Executive Order 13563 reaffirms the principles of E.O. 12866, 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.
12.
Financial assistance, Grant administration, Grant programs.
For the reasons set forth in the preamble, the Department of the Interior proposes to amend 2 CFR chapter XIV by adding part 1403 to read as follows:
5 U.S.C. 301; 2 CFR part 200.
The Financial Assistance Interior Regulation (FAIR) serves as the regulatory structure for the Department's financial assistance regulations that implement or supplement the OMB Omni-Circular, 2 CFR part 200.
The FAIR applies to all the Department of the Interior grant-making organizations and to any non-Federal entity that applies for, receives, operates, or expends funds from a Department Federal financial assistance award, cooperative agreement or grant.
The FAIR does not apply to tribal awards made in accordance with the Indian Self-Determination and Education Assistance Act (Public Law 93-638, 88 Stat. 2204), as amended. However, the FAIR does apply to discretionary grants or cooperative agreements awarded to Tribes pursuant to section 9 of Public Law 93-638 when mutually agreed to by the Secretary of the Interior and the tribal organization involved. The FAIR applies to all financial assistance awards within the Department, except where otherwise provided by Statute. Grants Officers must document statutory exceptions in the official award file.
Award recipients must follow bureau/office program specific policies and procedures and applicable government-wide requirements. In the event that a bureau's or office's specific policies and procedures conflict with 2 CFR part 200 or this part, the bureau/office will adhere to the provisions of 2 CFR part 200 and this part unless the policy/procedures are required by law.
(a)
(b)
(c)
(1) In any capacity, even if otherwise permissible, by any applicant or potential applicant for a Federal financial assistance award;
(2) Employment within the last 12 months with a different organization applying for some portion of the award's approved project activities and funding to complete them OR expected to apply for and to receive some portion of the award; and/or
(3) Employment with a different organization of any member of the organization employee's household or a relative with whom the organization's employee has a close personal relationship who is applying for some portion of the award's approved project activities and funding to complete them, OR expected to apply for and to receive some portion of the award.
(d)
(e)
(f)
(a) Non-Federal entities must disclose in writing any potential conflict of interest to the Department awarding agency or pass-through entity and the Department's Office of Inspector General in accordance with 2 CFR 200.112,
(b) Employees are prohibited from having a direct or indirect financial interest that conflicts substantially or appears to conflict substantially with his or her government duties and responsibilities (see 5 CFR 2635.402 and 5 CFR 2635.502). Employees are also prohibited from engaging in, either directly or indirectly, a financial transaction resulting from or primarily relying on information obtained through his or her government employment (see 5 CFR 2635.702 and 5 CFR 2635.703). In addition, 43 CFR 20.401-403 contains other regulations concerning conflicts of interest involving employees of specific bureaus and offices. Employee Responsibility and Conduct Regulations for the Department are contained in 43 CFR part 20, 5 CFR 2634, 5 CFR 2635, and 5 CFR 2640.
(c) With the exception of contracting personnel, proposal evaluators and advisors are not required to file a Statement of Employment and Financial Interest (DI-210) unless they occupy positions identified in 5 CFR 2634.202 and 5 CFR 2634.904. Therefore, upon receipt of a Memorandum of Appointment, each proposal evaluator and advisor must sign and return a Conflict of Interest Certificate to the Grants Officer or official responsible for the review. If an actual or potential conflict of interest exists, the appointee may not evaluate or provide advice on a potential applicant's proposal until the conflict has been resolved with the servicing Ethics Counselor. Signed certificates from all proposal evaluators and advisors must be retained in the master file for the Funding Opportunity Announcement.
(d) During the evaluation process, each proposal evaluator and advisor must assure that there are no financial or employment interests which conflict or give the appearance of conflicting with his or her duty to evaluate proposals impartially and objectively. Examples of situations which may be prohibited or represent a potential conflict of interest may include, but are not limited to:
(1) Financial interest, including ownership of stocks and bonds, in a firm which submits, or is expected to submit, an application in response to the funding opportunity;
(2) Outstanding financial commitments to any applicant or potential applicant;
(3) Employment in any capacity, even if otherwise permissible, by any applicant or potential applicant;
(4) Employment within the last 12 months by any applicant or potential applicant;
(5) Any non-vested pension or reemployment rights, or interest in profit sharing or stock bonus plan, arising out of the previous employment by an applicant or potential applicant;
(6) Employment of any member of the immediate family by any applicant or potential applicant;
(7) Positions of trust that may include employment, past or present, as an officer, director, trustee, general partner, agent, attorney, consultant, or contractor;
(8) A close personal relationship that may include a spouse, dependent child or member of the proposal evaluator's household that may compromise or impair the fairness and impartiality of the proposal evaluator or advisor and grants officer during the proposal evaluation and award selection process, and the management of an award; and
(9) Negotiation of outside employment with any applicant or potential applicant.
(e) Each proposal evaluator and advisor must immediately disclose in writing to the Grants Officer or the individual responsible for the review as soon as it becomes known that an actual or potential conflict of interest exists. The Grants Officer must obtain the assistance of the servicing Ethics Counselor in order to reach an opinion or resolution. A record of the disposition of all conflict of interest situations must be included in the award file.
(f) All Department financial assistance awards must include the following term and condition prohibiting recipient, recipient employee and subrecipient conflicts of interest:
The recipient must establish safeguards to prohibit its employees and subrecipients from using their positions for purposes that constitute or present the appearance of a personal or organizational conflict of interest. The recipient is responsible for notifying the Grants Officer in writing of any actual or potential conflicts of interest that may arise during the life of this award. Conflicts of interest include any relationship or matter which might place the recipient or its employees in a position of conflict, real or apparent, between their responsibilities under the agreement and any other outside interests. Conflicts of interest may also include, but are not limited to, direct or indirect financial interests, close personal relationships, positions of trust in outside organizations, consideration of future employment arrangements with a different organization, or decision-making affecting the award that would cause a reasonable person with knowledge of the relevant facts to question the impartiality of the recipient and/or recipient's employees and subrecipients in the matter.
The Grants Officer and the servicing Ethics Counselor will determine if a conflict of interest exists. If a conflict of interest exists, the Grants Officer will determine whether a mitigation plan is feasible. Mitigation plans must be approved by the Grants Officer in writing. Failure to resolve conflicts of interest in a manner that satisfies the government may be cause for termination of the award.
Failure to make required disclosures may result in any of the remedies described in 2 CFR 200.338, including suspension or debarment (see also 2 CFR part 180).
The non-Federal entity or applicant for a Federal award must disclose in writing, in a timely manner, to the Federal awarding agency or pass-through entity all violations of Federal criminal law involving fraud, bribery, or gratuity violations potentially affecting the Federal award. Failure to make required disclosures can result in any of the remedies described in 2 CFR 200.338 (see also 2 CFR part 180 and 31 U.S.C. 3321). A non-Federal entity or applicant for a the Department award must disclose, in a timely manner, in writing to the Department awarding agency or pass-through entity, and to the Department's Office of Inspector General, all violations of Federal criminal law involving fraud, bribery, or gratuity violations potentially affecting the Federal award.
(a) This merit review process does not apply to instruments such as intra- and inter-agency agreements, international agreements (excluding grants and cooperative agreements with foreign recipients), memoranda of understanding or agreement, cooperative research and development agreements, concession contracts, permits, or fixed price awards.
(b) This merit review process must be described or incorporated by reference in the applicable funding opportunity announcement (see 2 CFR part 200 appendix I and 2 CFR 200.203). It is also important for the Department's bureaus and offices to create review systems for discretionary programs that are noncompetitive that consider statutory or regulatory provisions, a business evaluation, risk assessment, and other applicable government-wide pre-award considerations.
(c)
(2)
(3)
(i) Merit review factors and sub-factors;
(ii) A rating system (
(iii) Evaluation standards or descriptions which explain the basis for
(iv) Program policy factors; and
(v) The basis for selection.
(4)
(5)
(i) The application meets the requirements of the applicable funding opportunity;
(ii) The applicant meets the eligibility requirements detailed in the funding opportunity;
(iii) The applicant entity and principal investigator/key personnel are not suspended, debarred, or otherwise described as ineligible in the System for Award Management; and
(iv) The application contains a properly executed Standard Form (SF)-424,
(6)
(7)
(8)
(9)
The Omni-Circular and the Department's FAIR Omni-Circular supplement apply to for-profit entities, foreign public entities or foreign organizations except where the Federal awarding agency determines that the application of these subparts would be inconsistent with the international obligations of the United States or the statute or regulations of a foreign government (see definitions in 2 CFR 200.46 and 2 CFR 200.47).
(a)
(2) Bureaus and offices may apply the administrative guidelines in 2 CFR part 200 subparts A through D; the cost principles at 48 CFR part 1, subpart 31.2; and the procedures for negotiating indirect costs detailed in section 1403.401 of the FAIR, to domestic for-profit entities
(3) Depending on the nature of a particular program, offices and bureaus may alternatively develop program-specific administrative guidelines for domestic for-profits based on the requirements in 2 CFR part 200 subparts A through D, but may not apply more restrictive requirements than the requirements in 2 CFR part 200 subparts A through D unless approved by OMB through a request to the Director, Office of Acquisition and Property Management.
(b)
(c)
(d)
(e)
(a)
(1) 2 CFR part 25, Universal Identifier and System for Award Management;
(2) 2 CFR part 170, Reporting Subawards and Executive Compensation;
(3) 2 CFR part 175, Award Term for Trafficking in Persons;
(4) 2 CFR part 1400, Government-wide Debarment and Suspension (Non-procurement);
(5) 2 CFR part 1401, Requirements for Drug-Free Workplace (Financial Assistance); and
(6) 43 CFR part 18, New Restrictions on Lobbying, always apply to domestic for-profit entities.
(b) Submission of an application for financial assistance also represents the applicant's certification of the statements in 43 CFR part 18, appendix A, Certification Regarding Lobbying.
(c) The terms and conditions of 41 U.S.C. 4712, Pilot Program for Enhancement of Recipient and Subrecipient Employee Whistleblower Protection, apply to all awards issued after July 1, 2013 and shall remain in effect until January 1, 2017.
(d) Bureaus and offices shall include the terms and conditions of 41 U.S.C. 6306, Prohibition on Members of Congress Making Contracts with the Federal Government, 41 U.S.C. 6306; and Executive Order 13513,
(e)
(f) Recipients, their subrecipients and contractors that are awarded contracts over the Simplified Acquisition Threshold related to an applicable award, shall inform their employees, in writing, in the predominant language of the workforce, of the employee whistleblower rights and protections under 41 U.S.C. 4712.
(g)
(f)
(g)
(2) Bureaus and offices must also include the terms and conditions of 41 U.S.C. 6306,
(h)
(2) State payment procedures in 2 CFR 200.305(a) do not apply. Foreign public entities must follow the payment procedures in 2 CFR 200.305(b)).
(3) The requirements of 2 CFR part 6 200.321,
(4) Foreign non-profit organizations (see definition in 2 CFR 200.70) are subject to the requirements specific to domestic non-profit organizations.
(5) Foreign institutions of higher education (IHEs) (institutions located outside the United States that meet the definition in 20 U.S.C. 1001) are subject to requirements specific domestic to IHEs.
(i)
(j)
(2) The provisions of 2 CFR part 200 appendix VII,
(3) The provisions of 45 CFR part 74, appendix E,
(4) Indirect costs for institutes of higher education are negotiated with HHS in accordance with 2 CFR part 200 appendix III,
(5) The applicable standard award terms and conditions will apply unless the recipient provides conclusive evidence for an exception. In granting the exception, the bureau/office agrees that the application of a particular requirement is inconsistent with the international obligations of the United States or the laws or regulations of a foreign government to which the recipient is subject. Such case-by-case exceptions are allowable under 2 CFR 200.102(b).
(6) The immunities provided to public international organizations under the International Organizations Immunities Act (22 U.S.C. 288-288f) are not considered waived unless they are expressly waived in writing by an authorized official at the organization. Signing the SF-424 Assurances or accepting an award does not constitute an express waiver of such immunities. The SF-424 Assurances form also states that “certain of these assurances may not be applicable to your project or program.” For a list of public international organizations awarded immunities under the International Organizations Immunities Act (see the U.S. Department of State's Foreign Affairs Manual (FAM), at 9 FAM 41.24, Exhibit I).
(a) The provisions of 2 CFR 200.414(c) require Federal agencies to accept federally negotiated indirect cost rates. Federal agencies may use a rate different from the negotiated rate for a class of awards or a single Federal award only when required by Federal statute or regulation, or when approved by a Federal awarding agency head or delegate based upon documented justification described within 2 CFR 200.414(c)(3). In addition, the Department accepts indirect cost rates that have been reduced or removed voluntarily by the proposed recipient of the award, on an award-specific basis. The following policies, procedures and general decision-making criteria apply for deviations from negotiated indirect cost rates for financial assistance programs and agreements.
(1)
(i) The same base identified in the recipient's negotiated indirect cost rate agreement, if the recipient has a federally negotiated indirect cost rate agreement; or
(ii) The modified total direct cost (MTDC) base, in cases where the recipient does not have a federally negotiated indirect cost rate agreement or, with prior approval of the Awarding Agency, when the recipient's federally negotiated indirect cost rate agreement base is only a subset of the MTDC (such as salaries and wages) and the use of the MTDC still results in an overall reduction in the total indirect cost recovered. The MTDC is the base defined by 2 CFR 200.68.
(iii) In cases where the recipient does not have a federally negotiated indirect cost rate agreement, under no circumstances will the Department use a modified rate based upon Total Direct Cost or other base not identified in the federally negotiated indirect cost rate agreement or defined within 2 CFR 200.68. The purpose of this restriction is to ensure that the reduced rate is applied against a base that does not include any potentially distorting items (such as pass-through funds, subcontracts in excess of $25,000, and participant support costs); and is based on the requirements outlined in 2 CFR 200.68; 2 CFR 200.414(f); 2 CFR part 200 appendix III, section C.2.; 2 CFR part 200 appendix IV, section B.3.f.; and appendix VII, section C.2.c.
(2)
(3)
(4)
(5)
(6)
(7)
(8) The following programs are approved to use an indirect cost rate that deviates from the federally negotiated indirect cost rate agreements:
(i) Cooperative Fish and Wildlife Research Unit (CRU) Program;
(ii) Cooperative Ecosystem Studies Unit (CESU) Program; and
(iii) Land Buy-Back Program for Tribal Nations.
(9)
(10)
(b) [Reserved]
Office of Personnel Management.
Proposed rule.
The Office of Personnel Management is issuing proposed regulations that introduce updated systems and regulatory definitions for managing human resources in the Federal Government. The rulemaking also proposes to reduce and clarify the reporting procedures that agencies are required to follow, creates a data-driven review process (HRStat); and describes workforce planning methods that agencies are required to follow.
Additionally, the proposed regulation aligns Strategic Human Capital Management to the Government Performance and Results Act Modernization Act of 2010 (Pub. L. 111-352). It also sets forth the new Human Capital Framework (HCF), which replaces the Human Capital Assessment Accountability Framework (HCAAF).
Comments must be received on or before April 8, 2016.
You may submit comments, identified by RIN number 3206-AL98, using any of the following methods:
For information contact Jan Chisolm-King by email at
The Office of Personnel Management (OPM) is issuing proposed regulations to revise 5 CFR part 250, subpart B, Strategic Human Capital Management and 5 CFR part 250, subpart C, Employee Surveys.
5 CFR part 250, subpart B, implements the requirements of 5 U.S.C. 1103(c) and the Chief Human Capital Officers Act (CHCO Act). Section 1103(c)(1) requires OPM to design a set of systems, including appropriate metrics, for assessing the management of human capital by Federal agencies and to define those systems in regulation. Section 1103(c)(2) requires OPM to define the systems in regulations and include standards addressing a series of specified topics. Subpart B of part 250 of title 5, Code of Federal Regulations, contains those regulations. Subpart B also provides an avenue for Chief Human Capital Officers (CHCOs) to carry out their required functions under 5 U.S.C. 1402(a).
Current regulations implement 5 U.S.C. 1103(c) by adopting the systems currently comprising the Human Capital Assessment and Accountability Framework (HCAAF) to constitute the systems required by 5 U.S.C. 1103(c)(1) and to provide the systems definitions and standards required by 5 U.S.C. 1103(c)(2). The HCAAF is a framework that integrates four human capital systems—Strategic Planning and Alignment, Talent Management, Performance Culture, and Evaluation. These systems define practices for the effective and efficient management of human capital and support the steps involved in the planning and goal setting, implementation, and evaluation of human capital policies, programs, and initiatives in the Federal Government.
In August, 2011, OPM issued proposed regulations (FR Doc No: 2011-19844) that sought to make several changes to the regulatory definitions related to the strategic management of human capital. The current regulations implement 5 U.S.C. 1103(c) by adopting the systems comprising the Human Capital Assessment and Accountability Framework (HCAAF) to constitute the systems required by 5 U.S.C. 1103(c)(1) and to provide the systems definitions and standards required by 5 U.S.C. 1103(c)(2). Having the HCAAF written into regulation makes it difficult to keep current. OPM concluded in 2011, as it does again today, that it would be more effective to provide definitions in the regulations that establish broad, overarching concepts, and to treat some of the system-specific material in the framework as guidance that is subject to change as Federal human capital management evolves. This removal of the HCAAF from the stated regulation into guidance would allow OPM to refresh aspects of the framework, without requiring a change to the specific regulations, thereby encouraging flexibility and adaptability. An additional change in the earlier proposal was the elimination of the requirement for the Strategic Human Capital Plan (SHCP) and Human Capital Management Report (HCMR) to reduce the burden of reporting requirements for the agencies.
In addition, the earlier proposed regulation would have clarified requirements imposed by two separate legal authorities. In the past, there was some confusion regarding whether agencies must establish separate accountability systems in order to satisfy the statutory requirements of 5 U.S.C. 1103(c)(2)(F) and any requirement OPM previously imposed under Civil Service Rule X (5 CFR 10.2). The proposed regulations were expected to make clear that the requirements of these two legal authorities are satisfied by the establishment of the Human Capital Accountability System (HCAS) set forth in section 250.205 of the proposed regulation.
OPM did not make the proposed regulation final because of several developments that required additional changes to what had been written in the proposed regulation. One major change was the enactment of the Government Performance and Results Act Modernization Act of 2010 (Pub. L. 111-352), and the issuance of the Diversity and Inclusion Executive Order (E.O. 13583).
Before the enactment of GPRAMA, agencies were required to develop Strategic Human Capital Plans that identified human capital (HC) strategies and resources that support agency missions and strategic goals. Under GPRAMA, agency strategic HC plans are no longer required; however, agencies must now integrate the human capital strategies and resources within their agency strategic plan. Human Capital Management Reports (HCMRs) also were eliminated. Implementation guidance for GPRAMA states that CHCOs will address in their Annual Performance Plan, “how performance
This information was previously reported in the agency HCMR. OPM is now introducing a requirement that agencies develop a process to monitor how the design and implementation of their respective human capital policies and programs support an agency's mission and strategic goals. Thus, the Annual Performance Plan and annual Human Capital Operation Plan (HCOP) will eliminate the requirement currently stated in section 250.203 to maintain a human capital plan.
In addition, the Diversity and Inclusion Executive Order supports the elimination of the SHCP and the HCMR through its emphasis on report consolidation—
A third reason that OPM did not make the proposed regulation final was because at the same time new regulations and executive orders were being proposed, OPM launched an initiative called Human Capital Assessment and Accountability Framework (HCAAF) Revitalization. The intent of the initiative was to update the set of systems and standards that have direct impact on how agencies carry out the planning, implementation, and evaluation of their HC initiatives/programs. The HCAAF Revitalization initiative identified innovative approaches that will help ensure that the framework continues to add value to Federal human capital professionals and program managers. As part of this revitalization effort, OPM conducted a thorough analysis of the current HCAAF framework, including a review of the initial goals and objectives of the framework, its flexibility, and how effectively it has been used in the current Federal environment, and identification of implementation challenges. Data on the current HCAAF and how it is used was obtained through the following venues:
• Interviews conducted with a wide range of subject matter experts (SMEs) knowledgeable about the HCAAF;
• administration of a questionnaire to human resources directors and program managers throughout the Federal Government;
• reviews of relevant documentation/literature provided by OPM, academic, and practitioner communities; and
• a roundtable meeting of noted human capital practitioners and experts from public and private sectors.
Based on this exhaustive review, OPM concluded that it would be more effective to discharge its obligations under 5 U.S.C. 1103(c)(2) by developing a Human Capital Framework (HCF) that is composed of four systems—Strategic Planning and Alignment, Performance Culture, Talent Management, and Evaluation.
The Human Capital Framework (HCF) is a framework that integrates four human capital systems—Strategic Planning and Alignment, Talent Management, Performance Culture, and Evaluation. These systems define good practices for effective and efficient human capital management and support the steps involved in the planning and goal setting, implementation, and evaluation of human capital initiatives in the Federal Government.
The proposed framework contains standards and focus areas. A standard is a consistent practice within human capital management in which agencies strive towards in each of the four HCF systems. The standards ensure that an agency's human capital management strategies, plans, and practices: (1) Are integrated with strategic plans, annual performance plans and goals, and other relevant budget, and acquisition plans; (2) contain measurable and observable performance targets; (3) are communicated in an open and transparent manner to facilitate cross-agency collaboration to achieve mission objectives; and (4) inform the development of human capital management priority goals for the Federal Government. The introduction of standards and monitoring of how they are implemented fosters an environment to establish progress measures. Focus areas are sound approaches that further define the system and must be integrated within agency strategic plans, annual performance plans and goals that contain measurable and observable performance targets and are communicated in an open and transparent manner to facilitate cross-agency collaboration to achieve mission objectives.
Finally, the proposed framework will include resources that can assist in the development, implementation, and monitoring of sound strategic human capital practices.
OPM is now issuing proposed regulations to revise 5 CFR part 250, subpart B, Strategic Human Capital Management. The proposed regulation will:
• Revise definitions to better align with statute.
• Implement 5 U.S.C 1103 by adopting the proposed new systems as required by 5 U.S.C. 1103(c)(1) and the proposed new systems, definitions, and standards as required by 5 U.S.C. 1103(c)(2). This new framework will integrate four human capital systems—Strategic Planning and Alignment, Performance Culture, Talent Management, and Evaluation. We expect that the new systems and system definitions will facilitate more effective alignment of human capital programs with agency mission objectives.
• Define the new systems and include the new standards as required by 5 U.S.C. 1103(c)(2) as a set of overarching concepts in regulation to be supplemented with details in guidance. OPM continues to believe that, under the current regulation, the incorporation of the full text of the HCAAF to satisfy the 5 U.S.C. 1103(c)(2) requirements has proven to undermine the original concept of the HCAAF with respect to flexibility and adaptability. The original HCAAF document was integrated several years ago into a web-based Resource Center that was updated based on feedback, analysis, and emerging agency practices and results. Once the entire text of the HCAAF was brought into regulation, it became difficult to keep current. OPM concluded that it would be more effective to discharge its obligations under 5 U.S.C. 1103(c)(2) by providing definitions in the regulations that establish broad, overarching concepts, and treating the specific material in the HCAAF as guidance that can be updated, as appropriate, as Federal human capital management evolves. This will allow OPM to refresh some aspects of the framework without requiring a change to the specific regulations thus encouraging flexibility and adaptability.
• Create the Human Capital Strategic Review (HCSR) process. The HCSRs will:
○ Enable OPM and agencies to monitor progress with achieving organizational outcomes by the presentation of synthesized evidence and information (indicators, evaluations/audits, and HRStat reviews);
○ provide OPM with the opportunity to identify cross-cutting themes to position OPM to develop governmentwide policies and strategies;
○ afford agencies with the opportunity to receive feedback from OPM to improve strategies and evaluation processes; and
○ identify opportunities for improvement that will enable decision making that leads to the prioritization of resources.
• Institutionalize a human capital performance improvement process, referred to as “HRStat” that identifies, measures, and analyzes human capital data to improve human capital outcomes. HRStat, a data-driven review process, will drive performance and alignment of achieving human capital goals related to the agency mission.
• Define the annual Human Capital Operation Plan, which supports an Agency Performance Plan.
• Restructure the requirements of Subpart B of Part 250 for agencies by removing the regulatory requirement for the HCMR. OPM proposes to monitor agency outcomes in human capital management through the Human Capital Evaluation Framework.
• Introduce workforce planning methods agencies are required to follow.
• Ensure consistency by clearly defining key human capital management terms.
The purpose of these proposed changes is to focus the regulations on the specific requirements that are the most significant for establishing and maintaining efficient and effective human capital management systems now and into the future, while providing agencies with flexibility in determining how they will accomplish their human capital activities.
5 CFR part 250, subpart C, implements the requirements of section 1128 of the National Defense Authorization Act for Fiscal Year 2004 (Pub. L. 108-136, sec.1128, codified at 5 U.S.C. 7101 note). Section 1128 of Public Law. 108-136 requires each Executive agency to conduct an annual survey of its employees to assess leadership and management practices that contribute to agency performance and employee satisfaction as it relates to five enumerated areas of work life. The law also requires OPM to “issue regulations prescribing survey questions that should appear on all agency surveys.” In addition, the law requires agencies to make the survey results available to the public and post the results on their Web sites, unless the head of the agency determines that doing so would jeopardize or negatively impact national security.
OPM issued a final regulation (5 CFR part 250, subpart C) including 45 specific survey questions on August 24, 2006. The requirement was for agencies to conduct an annual survey (“Annual Employee Survey”) with prescribed questions beginning in calendar year 2007. OPM's centralized Federal Employee Viewpoint Survey (FEVS) administration includes these survey questions. When the FEVS is administered governmentwide the burden for individual agencies to administer its own survey is alleviated. To modernize the survey, OPM is issuing proposed regulations to revise 5 CFR part 250, subpart C, Employee Surveys. The proposed regulation will:
• Reduce the number of specifically prescribed questions in the regulation:
A critical review of the FEVS questions currently in regulation was conducted by: (1) A cross-governmental agency task force convened by OPM (2011); and (2) by university researchers and published in the Public Administration Review (PAR) (Fernandez, Resh, Moldogaziev, and Oberfield, 2015) for the purpose of reviewing and revising the current questions. These reviews led to the formation of a group of OPM psychologists tasked with addressing these recommendations to further advance the survey program.
The cross-governmental agency task force, made up of survey experts from several agencies (
The PAR article, which reviewed more than 40 research articles based on FEVS data, indicates the validity of the FEVS would largely benefit from a revision to include stronger, relevant and unambiguous questions as well as questions that capture a single concept. The study also addressed the notion that in a revision of survey questions, the selection of relevant concepts and proper instrumentation should be grounded in a thorough review of the literature and sound theoretical reasoning.
The group of OPM psychologists analyzed and confirmed the external recommendations and proposed a final set of 11 questions that were selected based on adherence to and measurement of the areas in statute. The identified questions exhibit appropriate properties as metrics as reflected through psychometric analysis; and are clear and unambiguous in nature. These independent efforts support the inclusion of the set of questions proposed in this regulation. OPM will address specific item concerns at the conclusion of the open comment period.
• Modify the definitions of the terms used in the questions in regulation. Definitions were modified and clarified in response to comments received during the course of FEVS administration from (1) survey respondents, (2) agency leaders, and (3) the Senior Executive Association; and
• Modify the requirement for notification to OPM. Process improvements achieved by technical advances eliminate the regulatory need for agencies to submit data to OPM as OPM can readily access data from posts of agency results to their Web sites as required under § 250.303(a).
The Office of Management and Budget has reviewed this proposed rule in accordance with E.O. 13563 and 12866.
This document does not contain proposed information collection requirements subject to the Paperwork Reduction Act of 1995 (Pub. L. 104-13).
I certify that these regulations will not have a significant economic impact on a substantial number of small entities because they apply only to Federal agencies and employees.
Authority for personnel actions in agencies, Employee surveys, Strategic human capital management.
Accordingly, OPM is proposing to amend title 5, Code of Federal Regulations, as follows:
5 U.S.C. 105; 5 U.S.C. 1103 (a)(7), (c)(1), and (c)(2); 5 U.S.C. 1401; 5 U.S.C. 1402(a); 31 U.S.C. 1115(a)(3); 31 U.S.C. 1115(f); 31 U.S.C. 1116(d)(5); Public Law 103-62; Public Law 107-296; Public Law 108-136, 1128; Public Law 111-352; 5 C.F.R 10.2; FR Doc No: 2011-19844; E.O. 13583; E.O. 13583, Sec 2(b)(ii)
Pursuant to 5 U.S.C. 1103(c), this subpart defines a set of systems, including standards and metrics, for assessing the management of human capital by Federal agencies. These regulations apply to all Executive agencies as defined in 5 U.S.C. 105 and support the performance planning and reporting that is required by sections 1115(a)(3) and (f) and 1116(d)(5) of title 31, United States Code.
(1) Advise and assist the head of the agency and other agency officials in carrying out the agency's responsibilities for selecting, developing, training, and managing a high-quality, productive workforce in accordance with merit system principles; and
(2) Implement the rules and regulations of the President, the Office of Personnel Management (OPM), and the laws governing the civil service within the agency.
(1) Are integrated with strategic plans, annual performance plans and goals, and other relevant budget, finance, and acquisition plans;
(2) Contain measurable and observable performance targets;
(3) Are communicated in an open and transparent manner to facilitate cross-agency collaboration to achieve mission objectives; and
(4) Inform the development of human capital management priority goals for the Federal Government.
Strategic human capital management systems, standards, and focus areas are defined within the Human Capital Framework (HCF). The four systems described below provide definitions and standards for human capital planning, implementation, and evaluation. OPM may augment the definitions and standards set forth in this section with additional focus areas that the Director of OPM will publish in such form as the Director determines appropriate. The HCF systems and standards are:
(a)
(1) Integrate strategic plans, annual performance plans and goals, and other relevant budget, finance, and acquisition plans;
(2) Contain measurable and observable performance targets; and
(3) Communicate in an open and transparent manner to facilitate cross-agency collaboration to achieve mission objectives.
(b)
(1) Plan for and manage current and future workforce needs;
(2) Design, develop, and implement proven strategies and techniques and practices to attract, hire, develop, and retain talent; and
(3) Make progress toward closing any knowledge, skill, and competency gaps throughout the agency.
(c)
(1) Strategies and processes to foster a culture of engagement and collaboration;
(2) A diverse, results-oriented, high-performing workforce; and
(3) A performance management system that differentiates levels of performance of staff, provides regular feedback, and links individual performance to organizational goals.
(d)
(1) Ensuring compliance with merit system principles; and
(2) Identifying, implementing, and monitoring process improvements.
(a) An agency must use the systems and standards established in this part, and any metrics that OPM subsequently provides in guidance, to plan, implement, evaluate and improve human capital policies and programs. These policies and programs must—
(1) Align with Executive branch policies and priorities, as well as with individual agency missions, goals, and strategic objectives. Agencies must align their human capital management strategies to support the Federal Workforce Strategic Priorities Report, agency strategic plan, agency performance plan, and budgets prepared under OMB Circular A-11;
(2) Be based on comprehensive workforce planning and analysis;
(3) Monitor and address skills gaps within governmentwide and agency-specific mission critical occupations by using comprehensive data analytic methods and gap closure strategies;
(4) Recruit, hire, develop, and retain an effective workforce, especially in the agency's mission-critical occupations;
(5) Ensure leadership continuity by implementing and evaluating recruitment, development, and succession plans for leadership positions;
(6) Implement a knowledge management process to ensure continuity in knowledge sharing among employees at all levels within the organization;
(7) Sustain an agency culture that engages employees by defining, valuing, eliciting, and rewarding high performance; and
(8) Hold the agency head, executives, managers, human capital officers, and human capital staff accountable for efficient and effective strategic human capital management, in accordance with merit system principles.
(b) Each agency must meet the statutory requirements of the Government Performance and Results Act Modernization Act (GPRAMA) by including within the Annual Performance Plan (APP) human capital practices that are aligned to the APP. The human capital portion of the APP must include performance goals and indicators. Guidance on preparing the human capital portions of an agency's APP can be found in OMB Circular A-11, part 6, section 200.
(c) An agency's Deputy Secretary, or equivalent, is responsible for ensuring that the agency's strategic plan includes a description of the operational processes, skills and technology, and human capital information required to achieve the agency's goals and objectives. Specifically, the Deputy Secretary, or equivalent will—
(1) Allocate resources;
(2) Ensure the agency incorporates applicable priorities identified within the Federal Workforce Strategic Priorities Report and is working to close governmentwide and agency-specific skills gaps; and
(3) Participate with the senior management team in their agency's (at a minimum) quarterly HRStat reviews.
(d) Each agency must develop an annual Human Capital Operation Plan (HCOP) in support of the Federal human capital assessment and agency APP, to be reviewed annually, and updated if needed, as part of the agency's efforts to improve its human capital processes. The HCOP must demonstrate how an agency's human capital implementation strategies will meet an agency's mission and strategic goals (
(i) Be established through the coordination of a working group that is led by the agency's Chief Human Capital Officer and which should include the agency's Chief Operating Officer (COO), Performance Improvement Officer (PIO), Chief Information Officer (CIO), Chief Financial Officer (CFO), and Equal Employment Opportunity (EEO) Director to ensure that budget, technology, and performance processes are integrated to support human capital strategies and outcomes;
(ii) Support the design and implementation of the human capital strategy by approving the agency four-year annual Human Capital Operation Plan (AHCOP);
(iii) Be used to inform the development of an agency's strategic plan, because an agency's human capital can affect whether or not a strategy or strategic goal is achieved;
(iv) Explicitly describe the agency-specific skill and competency gaps that must be closed through the use of agency selected human capital strategies;
(v) Include annual human capital performance goals and measures that will support the evaluation of the agency's human capital strategies, through HRStat reviews, and that are aligned to support mission accomplishment;
(vi) Reflect the systems and standards defined in 250.203 above, consistent with their agency strategic plan and annual performance plan, to address strategic human capital priorities and goals; and
(vii) Address the governmentwide priorities identified in the Federal Workforce Strategic Priorities Report.
(e) Each agency must participate with OPM in a Human Capital Strategic Review (HCSR). The HCSR will be conducted during the evaluation phase and OPM will issue guidance about the HCSR requirements.
(f) The Chief Human Capital Officer must design, implement and monitor agency human capital policies and programs that—
(i) Ensure human capital activities support merit system principles;
(ii) Use the OPM designated method to identify governmentwide and agency-specific skills gaps;
(iii) Demonstrate how the agency is using the principles within the Human Capital Framework (HCF) to address strategic human capital priorities and goals;
(iv) Use the HRStat reviews, in coordination with the agency Performance Improvement Officer (PIO), to assess the agency's progress toward meeting its strategic and performance goals;
(v) Implement the HRStat Maturity guidelines specified by OPM;
(vi) Use HRStat reviews to evaluate their agency's progress;
(vii) Establish and maintain an Evaluation System to evaluate human capital outcomes that is—
(A) Formal and documented; and
(B) Approved by OPM;
(viii) Maintain an independent audit program, subject to full OPM participation and evaluation, to review periodically all human capital management systems and the agency's human resources transactions to ensure legal and regulatory compliance. An agency must—
(A) Take corrective action to eliminate deficiencies identified by OPM, or through the independent audit, and to improve its human capital management programs and its human resources processes and practices; and
(B) Based on OPM or independent audit findings, issue a report to its leadership and OPM containing the analysis, results, and corrective actions taken; and
(ix) Improve strategic human capital management by adjusting strategies and practices, as appropriate, after assessing the results of performance goals, indicators, and business analytics.
(g) The agency's human capital policies and programs must support the implementation and monitoring of the governmentwide Strategic Human Capital Strategy, which is published by OPM every four years, and—
(1) Improve strategic human capital management by using performance goals, indicators, and business analytics to assess results of the human capital management strategies planned and implemented;
(2) Ensure human capital activities support merit systems principles;
(3) Adjust human capital management strategies and practices in response to outcomes identified during quarterly data-driven reviews of human capital performance to improve organizational processes; and
(4) Use the governmentwide and agency-specific human capital strategies to inform resource requests (
OPM reserves the right to provide additional guidance regarding metrics as the need arises.
If OPM finds that an agency has taken an action contrary to a law, rule, regulation, or standard that OPM administers, OPM may require the agency to take corrective action. OPM may suspend or revoke a delegation agreement established under 5 U.S.C. 1104(a)(2) at any time if it determines that the agency is not adhering to the provisions of the agreement. OPM may suspend or withdraw any authority granted under this chapter to an agency, including any authority granted by delegation agreement, when OPM finds that the agency has not complied with qualification standards OPM has issued, instructions OPM has published, or the regulations in this chapter. OPM also may suspend or withdraw these authorities when it determines that doing so is in the interest of the civil service for any other reason.
5 U.S.C. 105; 5 U.S.C. 7101 note; Public Law 108-136
(a) Each executive agency must conduct an annual survey of its employees to assess topics outlined in the National Defense Authorization Act for Fiscal Year 2004, Pub. L. 108-136, sec.1128, codified at 5 U.S.C. 7101.
(b) Each executive agency may include additional survey questions unique to the agency in addition to the employee survey questions prescribed by OPM under paragraph (c) of this section.
(c) The 11 prescribed survey questions are listed in the following table:
(a) Each agency will make the results of its annual survey available to the public and post the results on its Web site unless the agency head determines that doing so would jeopardize or negatively impact national security. The posted survey results will include the following:
(1) The agency's evaluation of its survey results;
(2) How the survey was conducted;
(3) Description of the employee sample, unless all employees are surveyed;
(4) The survey questions and response choices with the prescribed questions identified;
(5) The number of employees surveyed and number of employees who completed the survey; and
(6) The number of respondents for each survey question and each response choice.
(b) Data must be collected by December 31 of each calendar year. Each agency must post the beginning and ending dates of its employee survey and either the survey results described in paragraph (a) of this section, or a statement noting the decision not to post, no later than 120 days after the agency completes survey administration. OPM may extend this date under unusual circumstances.
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 737-600, -700, -700C, -800, -900, and -900ER series airplanes. This proposed AD was prompted by a report of wire chafing damage, which caused an electrical arc to an adjacent hydraulic tube located on the forward bulkhead of the main landing gear (MLG) wheel well, resulting in a hole in a hydraulic tube and consequent total loss of system B hydraulic fluid. This proposed AD would require an inspection for chafing damage of wire bundles and a hydraulic tube in the right side of the MLG wheel well, and corrective action if necessary; and installation of clamps between the wire bundles and hydraulic tube. We are proposing this AD to prevent chafing damage, which could result in electrical arcing that can cause a hole in the hydraulic tube and consequent loss of hydraulic fluid, possibly resulting in a fire in the MLG wheel well.
We must receive comments on this proposed AD by March 24, 2016.
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 Boeing Commercial Airplanes, Attention: Data & Services Management, P. O. Box 3707, MC 2H-65, Seattle, WA 98124-2207; telephone 206-544-5000, extension 1; fax 206-766-5680; Internet
You may examine the AD docket on the Internet at
Sean J. Schauer, Aerospace Engineer, Systems and Equipment Branch, ANM-130S, FAA, Seattle Aircraft Certification Office (ACO), 1601 Lind Avenue SW., Renton, WA 98057-3356; phone: 425-917-6479; 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 of damage to wire W6128-0506-10. The wire had chafed and arced to an adjacent hydraulic tube located on the forward bulkhead of the MLG wheel well. The chafing and electrical arc created a small hole in a system B hydraulic tube and caused damage to the wire bundle, which resulted in a ground fault detection on the system A electrical motor-driven pump (EMDP). The small hole led to a total loss of system B hydraulic fluid and the ground fault resulted in removal of power from the system A EMDP and illumination of the system A EMDP low power light. An investigation found that there was not sufficient separation between the wire bundles W6128, W8122, and the adjacent hydraulic tube at that location. This condition, if not corrected, could result in electrical arcing that can cause
We reviewed Boeing Alert Service Bulletin 737-29A1119, dated August 4, 2015. The service information describes procedures for doing an inspection for chafing damage of the wire bundles and hydraulic tube in the right side of the MLG wheel well, corrective actions, and installation of clamps and an optional spacer between the wire bundles and hydraulic tube. 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
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. 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” are actions that correct or address any condition found. Corrective actions in an AD could include, for example, repairs.
We estimate that this proposed AD affects 1,270 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.
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 March 24, 2016.
None.
This AD applies to The Boeing Company Model 737-600, -700, -700C, -800, -900, and -900ER series airplanes, certificated in any category, as identified in Boeing Alert Service Bulletin 737-29A1119, dated August 4, 2015.
Air Transport Association (ATA) of America Code 29, Hydraulic power.
This AD was prompted by a report of wire chafing damage, which caused an electrical arc to an adjacent hydraulic tube located on the forward bulkhead of the main landing gear (MLG) wheel well, resulting in a hole in a hydraulic tube and consequent total loss of system B hydraulic fluid. We are issuing this AD to prevent chafing damage, which could result in electrical arcing that can cause a hole in the hydraulic tube and consequent loss of hydraulic fluid, possibly resulting in a fire in the MLG wheel well.
Comply with this AD within the compliance times specified, unless already done.
Within 24 months after the effective date of this AD: Do the actions specified in paragraphs (g)(1) and (g)(2) of this AD:
(1) Do a detailed inspection for chafing damage of the wire bundles and hydraulic tube in the right side of the MLG wheel well, and do all applicable corrective actions, in
(2) Install new clamps and an optional spacer between the wire bundles and hydraulic tube in the right side of the MLG wheel well, in accordance with the Accomplishment Instructions of Boeing Alert Service Bulletin 737-29A1119, dated August 4, 2015.
(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 (i)(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.
(1) For more information about this AD, contact Sean J. Schauer, Aerospace Engineer, Systems and Equipment Branch, ANM-130S, FAA, Seattle Aircraft Certification Office (ACO), 1601 Lind Avenue SW., Renton, WA 98057-3356; phone: 425-917-6479; fax: 425-917-6590; email:
(2) For service information identified in this AD, contact Boeing Commercial Airplanes, Attention: Data & Services Management, P. O. Box 3707, MC 2H-65, Seattle, WA 98124-2207; telephone 206-544-5000, extension 1; fax 206-766-5680; Internet
Office of Surface Mining Reclamation and Enforcement, Interior.
Proposed rule; public comment period and opportunity for public hearing on proposed amendment.
We, the Office of Surface Mining Reclamation and Enforcement (OSMRE), are announcing receipt of a proposed amendment to the Oklahoma regulatory program (Oklahoma program) under the Surface Mining Control and Reclamation Act of 1977 (SMCRA or the Act). Oklahoma proposes revisions to its regulations regarding: Permit eligibility for permits with violations on lands eligible for remining; permit suspension or rescission posting locations and appeal procedures; requiring GPS coordinates for aspects of permit maps; topsoil removal distances; blasting records requirements; annual reporting requirements; temporary cessation of operations requirements; casing and sealing temporary underground openings; right of entry requirements; surface drainage associated with auger mining; correcting reference errors; updating addresses; and correcting spelling and grammatical errors. Oklahoma intends to revise its program to be no less effective than the Federal regulations and to improve operational efficiency.
This document gives the times and locations that the Oklahoma program and this proposed amendment to that program are available for your inspection, the comment period during which you may submit written comments on the amendment, and the procedures that we will follow for the public hearing, if one is requested.
We will accept written comments on this amendment until 4:00 p.m., central time, March 9, 2016. If requested, we will hold a public hearing on the amendment on March 4, 2016. We will accept requests to speak at a hearing until 4:00 p.m., central time on February 23, 2016.
You may submit comments, identified by SATS No. OK-037-FOR, by any of the following methods:
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Elaine Ramsey, Director, Tulsa Field Office, Office of Surface Mining Reclamation and Enforcement, 1645 South 101st East Avenue, Suite 145, Tulsa, Oklahoma 74128-4629.
In addition, you may review a copy of the amendment during regular business hours at the following location: Oklahoma Department of Mines, 2915 N. Classen Blvd., Suite 213, Oklahoma City, Oklahoma 73106-5406. Telephone: (405) 427-3859.
Elaine Ramsey, Director, Tulsa Field Office. Telephone: (918) 581-6430.
Section 503(a) of the Act permits a State to assume primacy for the regulation of surface coal mining and reclamation operations on non-Federal and non-Indian lands within its borders by demonstrating that its program includes, among other things, “. . . State law which provides for the regulation of surface coal mining and reclamation operations in accordance with the requirements of this Act . . .;
By letter dated September 25, 2015 (Administrative Record No. OK-1003), Oklahoma sent us an amendment to its program under SMCRA (30 U.S.C. 1201
Oklahoma proposes to make substantive changes to Title 460. Department of Mines: Chapter 20, The Permanent Regulations Governing the Coal Reclamation Act of 1979, in the following subchapters. Additionally, Oklahoma plans on making several non-substantive changes throughout its regulations regarding updating addresses, correcting reference errors, grammatical corrections, and spelling errors.
Oklahoma proposes to revoke section 460:20-15-6.7(a)(2)(A) regarding permits issued before September 30, 2004.
Oklahoma proposes to add new a requirement that suspension or rescission notices be posted at the field office closest to the permit area at 460:20-15-10.1(c)(2)
Oklahoma proposes to clarify the suspension and rescission appeal process at 460:20-15-10.1(d) and (e).
Oklahoma proposes to add the requirements for GPS coordinates for each building on permit application maps at section 460:20-29-10(4).
Oklahoma proposes to add the permitting requirement to list the depth to mined coal in section 460:20-29-11(a)(5).
Oklahoma proposes to add language regarding minimum topsoil removal distance from the active pit in section 460:20-43-7(a)(1).
Oklahoma proposes to add new language regarding blasting records in section 460:20-43-23.
Oklahoma proposes to add new language regarding annual reporting requirements for contemporaneous reclamation in section 460:20-43-37(2).
Oklahoma proposes to add new language regarding qualification standards for temporary cessation of operations in section 460:20-43-49(a) and (c).
Oklahoma proposes to add language regarding casing and sealing underground openings during temporary cessation of operations in section 460:20-45-5(c).
Oklahoma proposes to add language regarding right of entry information in section 460:20-45-17(b).
Oklahoma proposes to add new language regarding surface drainage during auger mining operations in section 460:20-47-4(d).
Under the provisions of 30 CFR 732.17(h), we are seeking your comments on whether the amendment satisfies the applicable program approval criteria of 30 CFR 732.15. If we approve the amendment, it will become part of the State program.
If you submit written comments, they should be specific, confined to issues pertinent to the proposed regulations, and explain the reason for any recommended change(s). We appreciate any and all comments, but those most useful and likely to influence decisions on the final regulations will be those that either involve personal experience or include citations to and analyses of SMCRA, its legislative history, its implementing regulations, case law, other pertinent State or Federal laws or regulations, technical literature, or other relevant publications.
We cannot ensure that comments received after the close of the comment period (see
Before including your address, phone number, email address, or other personally identifiable information in your comment, you should be aware that your entire comment including your personally identifiable information, may be made publicly available at any time. While you can ask us in your comment to withhold your personally identifiable information from public review, we cannot guarantee that we will be able to do so.
If you wish to speak at the public hearing, contact the person listed under
To assist the transcriber and ensure an accurate record, we request, if possible, that each person who speaks at the public hearing provide us with a written copy of his or her comments. The public hearing will continue on the specified date until everyone scheduled to speak has been given an opportunity to be heard. If you are in the audience and have not been scheduled to speak and wish to do so, you will be allowed to speak after those who have been scheduled. We will end the hearing after everyone scheduled to speak and others present in the audience who wish to speak, have been heard.
If only one person requests an opportunity to speak, we may hold a public meeting rather than a public hearing. If you wish to meet with us to discuss the amendment, please request a meeting by contacting the person listed under
This rule is exempted from review by the Office of Management and Budget (OMB) under Executive Order 12866.
When a State submits a program amendment to OSMRE for review, our regulations at 30 CFR 732.17(h) require us to publish a notice in the
Intergovernmental relations, Surface mining, Underground mining.
This document was received by the Office the Federal Register on February 3, 2016.
Office of Surface Mining Reclamation and Enforcement, Interior.
Proposed rule; reopening of the public comment period.
We are reopening the public comment period on the proposed amendment to the Virginia regulatory program (the Virginia program) published on October 22, 2015. The comment period is being reopened in order to afford the public more time to comment. Virginia is proposing to revise its regulations in light of legislative changes made by the General Assembly of Virginia. If approved, the proposed amendment would incorporate these legislative changes into the approved State program. Additionally, the state regulations would be amended to revise the language of the public participation regulations to clarify proof of publication, remove the self-bonding instrument, and remove duplicate pool bond regulations already addressed under the Code of Virginia.
We will accept written comments on this amendment until 4:00 p.m., Eastern Standard Time (E.S.T.), March 9, 2016.
You may submit comments, identified by SATS No. VA-127-FOR, Docket ID: OSM-2015-003 by any of the following methods:
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In addition, you may review a copy of the amendment during regular business hours at the following location: Mr. Harve A. Mooney, Legal Services Officer, Virginia Department of Mines, Minerals and Energy, 3405 Mountain Empire Road, Big Stone Gap, Virginia 24219.
Mr. Earl Bandy, Field Office Director, Knoxville Field Office. Telephone: (865) 545-4103 ext 186. Email:
On October 22, 2015, we published a proposed rule in the
On November 18, 2015, we received a request from an attorney representing Southern Appalachian Mountain Stewards and the Sierra Club to extend the public comment period (Administrative Record No. VA 2027). We are granting the request to afford the public more time to comment on the amendment.
The full text of the program amendment is available for you to read at the locations listed above under
Department of Veterans Affairs.
Proposed rule.
The Department of Veterans Affairs (VA) is proposing to remove its medical regulation that governs medications provided in Alaska and territories and possessions of the United States because this regulation is otherwise subsumed by another VA medical regulation related to provision of medications that are prescribed by non-VA providers.
Comments must be received by VA on or before April 8, 2016.
Written comments may be submitted: By mail or hand-delivery to Director, Regulations Management (02REG), Department of Veterans Affairs, 810 Vermont Avenue NW., Room 1068, Washington, DC 20420; by fax to (202) 273-9026; or through
Kristin J. Cunningham, Director, Business Policy, Chief Business Office (10NB6), Veterans Health Administration, Department of Veterans Affairs, 810 Vermont Ave. NW., Washington, DC 20420; (202) 382-2508. (This is not a toll-free number.)
Under section 1712(d) of title 38 United States Code (U.S.C.), VA must furnish medications to veterans who receive increased compensation or pension benefits by reason of being permanently housebound or in need of regular aid and attendance, if such medications are prescribed for the treatment of any injury or illness suffered by such veteran. Section 1712(d) is distinct from the more general authority under 38 U.S.C. 1710 to provide medications to veterans as hospital care and medical services; veterans under section 1712(d) do not have to be receiving VA hospital care or medical services as a condition of VA furnishing medications to treat their injury or illness. VA originally promulgated two regulations on October 4, 1967, to implement section 1712(d), in title 38 Code of Federal Regulations (CFR) 17.60d and 17.60e. See 32 FR 13816. Because section 1712(d) does not require these certain veterans to be receiving VA hospital care or medical services as a condition of receiving medications from VA, § 17.60d provided that VA pharmacies would fill prescriptions for these veterans if such prescriptions were “not part of authorized Veterans Administration hospital or outpatient care,” and were “ordered by a private or non-VA” provider, and if the medications were “prescribed as specific therapy in the treatment of any of the veteran's illnesses or injuries.” See 32 FR 13816 (October 4, 1967). Section 17.60e, in turn, addressed geographic areas that, at the time, did not have VA pharmacies—§ 17.60e provided that in those areas without VA pharmacies, VA may reimburse the cost of prescriptions that otherwise would have been filled under § 17.60d. See 32 CFR 13816 (October 4, 1967). The intent of § 17.60e was to supplement § 17.60d, to ensure that eligible veterans under section 1712(d) and § 17.60d were able to have their medications furnished by VA, even if such veterans lived in Alaska and territories and possessions of the U.S. where there were no VA pharmacies.
Sections 17.60d and 17.60e were renumbered as §§ 17.96 and 17.97, respectively, and § 17.97 was further revised at that time to remove reference to the former § 17.60d and to insert a reference to the relevant section 1712 authority. See 61 FR 21964 (May 13, 1996). Section 17.96 was later revised to permit the filling of prescriptions by non-VA pharmacies in state homes under contract with VA. 63 FR 37779 (July 14, 1998). Sections 17.96 and 17.97 relate to the same cohort of veterans for whom VA is authorized to provide prescription medication under section 1712(d), and § 17.97 was intended to supplement § 17.96, although the supplementing effect of § 17.97 is not as apparent as when these regulations were first promulgated as §§ 17.60d and 17.60e. Because the same cohort of veterans is at issue in §§ 17.96 and 17.97, and because § 17.96 already provides for the filling of prescriptions in non-VA pharmacies, a separate § 17.97 to address prescriptions in non-VA pharmacies (pharmacies in areas without VA pharmacies) is no longer necessary. We would, therefore, remove § 17.97 and mark it reserved for future use, and would revise § 17.96 to clarify that any non-VA pharmacy under contract with VA may be used, not just those non-VA pharmacies in state homes.
The Code of Federal Regulations, as proposed to be revised by this rulemaking, would represent the exclusive legal authority on this subject. No contrary rules or procedures would be authorized. All VA guidance would be read to conform with this proposed rulemaking if possible or, if not possible, such guidance would be superseded by this rulemaking.
This proposed rule contains no provisions constituting a collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3521).
The Secretary hereby certifies that this proposed rule would not have a significant economic impact on a substantial number of small entities as they are defined in the Regulatory Flexibility Act, 5 U.S.C. 601-612. This proposed rule would directly affect only individuals and would not directly affect small entities. Therefore, pursuant to 5 U.S.C. 605(b), this amendment would be exempt from the initial and final regulatory flexibility analysis requirements of 5 U.S.C. 603 and 604.
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, when regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, and other advantages; distributive impacts; and equity). Executive Order 13563 (Improving Regulation and Regulatory Review) emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules, and promoting flexibility. Executive Order 12866 (Regulatory Planning and Review) defines a “significant regulatory action,” requiring review by the Office of Management and Budget (OMB) as “any regulatory action that is likely to result in a rule that may: (1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities; (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 this Executive Order.”
The economic, interagency, budgetary, legal, and policy implications of this proposed rule have been examined, and it has been determined not to be a significant
The Unfunded Mandates Reform Act of 1995 requires, at 2 U.S.C. 1532, that agencies prepare an assessment of anticipated costs and benefits before issuing any rule that may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more (adjusted annually for inflation) in any one year. This proposed rule would have no such effect on State, local, and tribal governments, or on the private sector.
The Catalog of Federal Domestic Assistance numbers and titles for the programs affected by this document are 64.007, Blind Rehabilitation Centers; 64.008, Veterans Domiciliary Care; 64.009, Veterans Medical Care Benefits; 64.010, Veterans Nursing Home Care; 64.011, Veterans Dental Care; 64.012, Veterans Prescription Service; 64.014, Veterans State Domiciliary Care; 64.015, Veterans State Nursing Home Care; 64.018, Sharing Specialized Medical Resources; 64.019, Veterans Rehabilitation Alcohol and Drug Dependence; 64.022, Veterans Home Based Primary Care; and 64.024, VA Homeless Providers Grant and Per Diem Program.
The Secretary of Veterans Affairs, or designee, approved this document and authorized the undersigned to sign and submit the document to the Office of the Federal Register for publication electronically as an official document of the Department of Veterans Affairs. Robert D. Snyder, Interim Chief of Staff, Department of Veterans Affairs, approved this document on January 29, 2016, for publication.
Administrative practice and procedure, Alcohol abuse, Alcoholism, Claims, Day care, Dental health, Drug abuse, Health care, Health facilities, Health professions, Health records, Homeless, Mental health programs, Nursing homes, Veterans.
For the reasons set forth in the preamble, we propose to amend 38 CFR part 17 as follows:
38 U.S.C. 501, and as noted in specific sections.
Any prescription, which is not part of authorized Department of Veterans Affairs hospital or outpatient care, for drugs and medicines ordered by a private or non-Department of Veterans Affairs doctor of medicine or doctor of osteopathy duly licensed to practice in the jurisdiction where the prescription is written, shall be filled by a Department of Veterans Affairs pharmacy or a non-VA pharmacy under contract with VA, to include non-VA pharmacy in a state home under contract with VA for filling prescriptions for patients in state homes, provided:
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) is proposing to approve revisions to the California Department of Pesticide Regulations (CDPR) portion of the California State Implementation Plan (SIP). These revisions concern emissions of volatile organic compounds (VOCs) from pesticides. We are proposing to approve these rules to regulate these emission sources under the Clean Air Act (CAA or the Act). We are taking comments on this proposal and plan to follow with a final action.
Any comments must arrive by March 9, 2016.
Submit your comments, identified by Docket ID No. EPA-R09-OAR-2015-0807 at
Nancy Levin, EPA Region IX, (415) 972-3848,
Throughout this document, “we,” “us” and “our” refer to the EPA.
This proposal addresses additions and amendments to Title 3 of the California Code of Regulations (3 CCR) made by CDPR Regulation 12-001 (“Nonfumigant Regulations”). Table 1 lists the new and amended regulations with the dates that they were adopted by the CDPR and submitted by the California Air Resources Board (CARB).
On August 4, 2015, the submittal for CDPR's Nonfumigant Regulations was deemed by operation of law to meet the completeness criteria in 40 CFR part 51 Appendix V, which must be met before formal EPA review.
There are no previous versions of 3 CCR 6558, 6577, 6864, 6880, 6883, 6884, or 6886 in the SIP. We approved earlier versions of 3 CCR 6452, 6452.2 and 6452.4 (now 6881) into the SIP on October 26, 2012 (77 FR 65294).
VOCs help produce ground-level ozone, smog and PM, which harm human health and the environment. Section 110(a) of the CAA requires States to submit regulations that control VOC emissions. The overall purpose of the new and amended regulations is to regulate certain nonfumigant pesticide products applied to certain crops in the SJV ozone NAA when VOC emissions meet or exceed 95% of the 18.1 tons per day limit on VOC emissions, or 17.2 tons per day. CDPR added or revised the rules specified above largely to establish limits on the sale and use of high-VOC formulations of nonfumigant pesticide products that contain abamectin, chlorpyrifos, gibberellins, or oxyfluorfen as their primary active ingredient, for use on any of the following seven crops: Alfalfa, almond, citrus, cotton, grape, pistachio, and walnut. These restrictions are only triggered when the VOC emissions meet or exceed 17.2 tons per day, as reported in the CDPR's Annual VOC Emissions Inventory Report. They apply only during the May-October “ozone season.” Once high-VOC product prohibitions are in effect, they must remain in effect until the “hypothetical emissions” (
The EPA's technical support document (TSD) has more information about these rules.
SIP rules must be enforceable (see CAA section 110(a)(2)), must not interfere with applicable requirements concerning attainment and reasonable further progress or other CAA requirements (see CAA section 110(l)), and must not modify certain SIP control requirements in nonattainment areas without ensuring equivalent or greater emissions reductions (see CAA section 193).
Generally, SIP rules must require Reasonably Available Control Technology (RACT) for each category of sources covered by a Control Techniques Guidelines (CTG) document as well as each major source of VOCs in ozone nonattainment areas classified as moderate or above (see CAA section 182(b)(2)). Because there are no relevant EPA CTG documents and because there are no major sources of VOCs for nonfumigant pesticides, nonfumigant pesticides are not subject to RACT requirements. However, nonfumigant pesticide use is subject to other VOC limits and requirements described in the TSD.
Guidance and policy documents that we use to evaluate enforceability, revision/relaxation and rule stringency requirements for the applicable criteria pollutants include the following:
We believe these rules are consistent with CAA requirements and relevant guidance regarding enforceability, stringency, and SIP revisions. The TSD has more information on our evaluation.
The TSD describes additional rule revisions that we recommend for the next time the local agency modifies the rules but are not currently the basis for rule disapproval.
As authorized in section 110(k)(3) of the Act, the EPA proposes to fully approve the submitted rules because we believe they fulfill all relevant requirements. We will accept comments
In this rule, the EPA is proposing to include in a final EPA rule regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is proposing to incorporate by reference the CDPR rules as described in Table 1 of this notice. The EPA has made, and will continue to make, these documents available electronically through
Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, the EPA's role is to approve State choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this proposed action merely proposes to approve State law as meeting Federal requirements and does not impose additional requirements beyond those imposed by State law. For that reason, this proposed action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Order 12866 (58 FR 51735, October 4, 1993);
• does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the Clean Air Act; and
• does not provide the EPA with the discretionary authority to address disproportionate human health or environmental effects with practical, appropriate, and legally permissible methods under Executive Order 12898 (59 FR 7629, February 16, 1994).
In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where the EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
42 U.S.C. 7401
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) is proposing to approve elements of State Implementation Plan (SIP) submissions from the State of Texas for Ozone (O
Written comments must be received on or before March 9, 2016.
Submit your comments, identified by Docket No. EPA-R06-OAR-2012-0953 at
Sherry Fuerst, telephone (214) 665-6454,
Throughout this document, “we,” “us,” or “our” means the EPA.
On March 12, 2008, we revised the primary and secondary O
Likewise, on January 22, 2010, we revised the primary national ambient air quality standard (hereafter the 2010 NO
Each state must submit an i-SIP within three years after the promulgation of a new or revised NAAQS. Section 110(a)(2) of the CAA includes a list of specific elements the i-SIP must meet. We issued guidance addressing the i-SIP elements for NAAQS.
We are proposing to approve the Texas i-SIP submittals for the 2008 Ozone and 2010 NO
Below is a summary of our evaluation of the Texas i-SIP for the relevant elements of 110(a)(2) we are proposing to approve. Texas provided demonstrations of how the existing Texas SIP meets the requirements of the 2010 NO
The Texas Clean Air Act (TCAA) provides the TCEQ, its Chairman, and its Executive Director with broad legal authority. They can adopt emission standards and compliance schedules applicable to regulated entities; emission standards and limitations and any other measures necessary for attainment and maintenance of national standards; and, enforce applicable laws, regulations, standards and compliance schedules, and seek injunctive relief. This authority has been employed in the past to adopt and submit multiple revisions to the Texas SIP. The approved SIP for Texas is documented at 40 CFR part 52.2270. TCEQ's air quality rules and standards are codified at Title 30, Part 1 of the Texas Administrative Code (TAC). Numerous parts of the regulations codified into 30 TAC necessary for implementing and enforcing the NAAQS have been adopted into the SIP.
The TCAA provides the authority allowing the TCEQ to collect air monitoring data, quality-assure the results, and report the data. TCEQ maintains and operates a monitoring network to measure levels of Ozone and NO
The Texas i-SIP submittal discussed the requirements of the CAA section 110(a)(2)(D). We plan to evaluate and take action on the portion of the i-SIP pertaining to emissions which will contribute significantly to nonattainment or interfere with maintenance of the O
Because Texas has a fully approved Prevention of Significant Deterioration (PSD) SIP addressing all regulated new source review pollutants, we propose to approve the transport portion of both submittals. Revisions to the PSD SIP were approved on October 22, 2014 (79 FR 66626, November 10, 2014).
We proposed to disapprove the portion of the SIPs addressing visibility protection for both O
CAA section 110(a)(2)(D)(ii) requires that the SIP contain adequate provisions insuring compliance with the applicable requirements of section 126 (relating to interstate pollution abatement) and 115 (relating to international pollution abatement). Texas meets the section 126 requirements as it has a fully approved PSD SIP and no source or sources have been identified by us as having any interstate impacts under section 126 in any pending action related to any air pollutant. Texas meets the section 115 requirements as there are no final findings by us that Texas air emissions affect other countries. Therefore, we propose to approve the portion of the Texas O
These i-SIP submissions for the 2008 O
With respect to funding, the TCAA requires TCEQ to establish an emissions fee schedule for sources in order to fund the reasonable costs of administering various air pollution control programs and authorizes TCEQ to collect additional fees necessary to cover reasonable costs associated with processing of air permit applications. We conduct periodic program reviews to ensure that the state has adequate resources and funding to, among other things, implement and enforce the SIP.
As required by the CAA, the Texas statutes and the SIP stipulate that any board or body, which approves permits or enforcement orders, must have at least a majority of members who represent the public interest and do not derive any “significant portion” of their income from persons subject to permits and enforcement orders or who appear before the board on issues related to the CAA or the TCAA. The members of the board or body, or the head of an agency with similar powers, are required to adequately disclose any potential conflicts of interest.
With respect to assurances that the State has responsibility to implement
The TCAA authorizes the TCEQ to require persons engaged in operations which result in air pollution to monitor or test emissions and to file reports containing information relating to the nature and amount of emissions. There are also SIP-approved state regulations pertaining to sampling and testing and requirements for reporting of emissions inventories In addition, SIP-approved rules establish general requirements for maintaining records and reporting emissions.
The TCEQ uses this information, in addition to information obtained from other sources, to track progress towards maintaining the NAAQS, developing control and maintenance strategies, identifying sources and general emission levels, and determining compliance with SIP-approved regulations and additional EPA requirements. The SIP requires this information be made available to the public. Provisions concerning the handling of confidential data and proprietary business information are included in the SIP-approved regulations. These rules specifically exclude from confidential treatment any records concerning the nature and amount of emissions reported by sources.
The TCAA provides TCEQ with authority to address environmental emergencies, and TCEQ has contingency plans to implement emergency episode provisions. Upon a finding that any owner/operator is unreasonably affecting the public health, safety or welfare, or the health of animal or plant life or property, the TCAA and 30 TAC chapters 35 and 118 authorize TCEQ to, after a reasonable attempt to give notice, declare a state of emergency and issue without hearing an emergency special order directing the owner/operator to cease such pollution immediately.
The “Texas Air Quality Control Contingency Plan for Prevention of Air Pollution Episodes” is part of the Texas SIP. However, because of the low levels of NO
The TCAA authorizes the TCEQ to revise the Texas SIP, as necessary, to account for revisions of an existing NAAQS, establishment of a new NAAQS, to attain and maintain a NAAQS, to abate air pollution, to adopt more effective methods of attaining a NAAQS, and to respond to EPA SIP calls concerning NAAQS adoption or implementation.
In 2012, we designated all areas in the United States as “unclassifiable/attainment” for the one-hour NO
However, as noted earlier, we do not expect infrastructure SIP submissions to address subsection (I). The specific SIP submissions for designated nonattainment areas, as required under CAA title I, part D, are subject to different submission schedules than those for section 110 infrastructure elements. Instead, we will take action on part D attainment plan SIP submissions through a separate rulemaking process governed by the requirements for nonattainment areas, as described in part D.
The TCEQ has the power and duty, under the TCAA to develop facts and investigate providing for the functions of environmental air quality assessment. Past modeling and emissions reductions measures have been submitted by the State and approved into the SIP. In addition to the ability to perform modeling for nonattainment SIPs, Texas has the ability to perform modeling on a case by case permit basis consistent with their SIP-approved PSD rules and with our guidance.
The TCAA authorizes and requires TCEQ to cooperate with the federal government and local authorities concerning matters of common interest in the field of air quality control, thereby allowing the agency to make such submissions to the EPA.
See the discussion for element (E) above for the description of the mandatory collection of permitting fees outlined in the SIP.
See discussion for element (J)(1) and (2) above for a description of the SIP's public participation process, the authority to advise and consult, and the PSD SIP's public participation requirements. Additionally, the TCAA also requires initiation of cooperative action between local authorities and the TCEQ, between one local authority and another, or among any combination of local authorities and the TCEQ for control of air pollution in areas having related air pollution problems that overlap the boundaries of political subdivisions, and entering into agreements and compacts with adjoining states and Indian tribes, where appropriate. TCEQ has a long history of successful cooperation with affected local entities. The transportation conformity component of the Texas SIP requires that interagency consultation and opportunity for public involvement be provided before making transportation conformity determinations and before adopting applicable SIP revisions on transportation-related issues.
EPA is proposing to approve portions of the December 13, 2012 and December 7, 2012, infrastructure SIP submissions from Texas, which address the requirements of CAA sections 110(a)(1) and (2) as applicable to the 2008 O
Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this action merely proposes to approve state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).
The SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the proposed rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Interstate transport of pollution, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Visibility.
42 U.S.C. 7401
Defense Acquisition Regulations System, Department of Defense (DoD).
Advance notice of proposed rulemaking.
DoD is seeking information that will assist in the development of a revision to the DFARS to ensure that substantial future independent research and development (IR&D) expenses as a means to reduce evaluated bid prices in competitive source selections are evaluated in a uniform way during competitive source selections. In addition to the request for written comments on this proposed rulemaking, DoD will hold a public meeting to hear the views of interested parties.
Individuals wishing to attend the public meeting should register by February 25, 2016, to ensure adequate accommodations, to facilitate entry into the building, and to create an attendee list for secure entry to the GSA building for anyone who is not a Federal Government employee with a Government badge. Interested parties may register at the Web site,
• Company or organization name;
• Names, telephone numbers and email addresses of persons planning to attend;
• Last four digits of social security number for each attendee (non-Federal employees only); and
• Identify if company or organization desires to make a presentation; limit to one presentation per company or organization. Presentations will be limited to approximately 10 minutes as time permits.
One valid, government-issued photo identification card will be required to enter the building. Non-U.S. citizens may use their valid passport as photo identification. Attendees are encouraged to arrive at least 30 minutes early to accommodate security procedures.
Submit comments identified by DFARS Case 2016-D017, using any of the following methods:
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Comments received generally will be posted without change to
Mr. Mark Gomersall, telephone 571-372-6099; facsimile 571-372-6101.
As expressed in the “Implementation Directive for Better Buying Power 3.0—Achieving Dominant Capabilities Through Technical Excellence and Innovation,” dated April 9, 2015, the Under Secretary of Defense for Acquisition, Technology and Logistics noted a concern when “promised future IRAD [Independent Research and Development] expenditures are used to substantially reduce the bid price on competitive procurements. In these cases, development price proposals are reduced by using a separate source of government funding (allowable IRAD overhead expenses spread across the total business) to gain a price advantage in a specific competitive bid. This is not the intended purpose of making IRAD an allowable cost.”
DoD is considering a proposed approach whereby solicitations would require offerors to describe in detail the nature and value of prospective IR&D projects on which the offeror would rely to perform the resultant contract. Then, as a standard approach, DoD would evaluate proposals in a manner that would take into account that reliance by adjusting the total evaluated price to the Government, for evaluation purposes only, to include the value of related future IR&D projects.
DoD is seeking comments on this planned approach in order to assist in the development of a proposed DFARS rule. Specifically, the Department is interested in understanding whether the planned approach would achieve the objective of treating the proposed use of substantial future IR&D expenses as a
Government procurement.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of public meeting.
The National Marine Fisheries Service will hold a public webinar to present details of a previously issued proposed rule (which published December 29, 2015) for electronic filing of seafood trade documents and will allow time for questions from the public.
The meeting will be held Wednesday, September, 17, 2016, from 3 p.m. until 4 p.m. eastern standard time. Written comments on the proposed rule (December 29, 2015; 80 FR 81251) must be received by February 29, 2016.
For information about connecting and system requirements to attend the webinar, visit:
Public comment on the proposed rule should be submitted by February 29, 2016 through
Mark Wildman, Office of International Affairs and Seafood Inspection; telephone: (301) 427-8350.
On December 29, 2015, NMFS published a proposed rule (80 FR 81251) to integrate three currently paper-based seafood trade monitoring programs within the scope of electronic data collection through the U.S. government-wide International Trade Data System. Background information on the proposed rule is provided at:
The meeting is physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Mark Wildman at (301) 427-8350 at least 5 days prior to the meeting date.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Proposed rule; request for comments.
NMFS issues a proposed rule that would implement Amendment 109 to the Fishery Management Plan for Groundfish of the Bering Sea and Aleutian Islands Management Area (FMP). If approved, this proposed rule would amend regulations governing the Western Alaska Community Development Quota (CDQ) Program to support increased participation in the groundfish CDQ fisheries (primarily Pacific cod) by catcher vessels less than or equal to 46 feet (ft) (14.0 meters (m)) length overall (LOA) using hook-and-line gear. Specifically, this proposed rule would exempt operators of registered catcher vessels greater than 32 ft (9.8 m) LOA and less than or equal to 46 ft LOA using hook-and-line gear from the requirement to obtain and carry a License Limitation Program license when groundfish CDQ fishing. The proposed rule also would reduce observer coverage requirements for catcher vessels less than or equal to 46 ft LOA when groundfish CDQ fishing, and implement new in-season management and catch accounting requirements to properly account for the harvest of groundfish and halibut and the accrual of halibut prohibited species catch in these fisheries. In addition to the proposed regulations necessary to implement Amendment 109, NMFS proposes to remove a table in the regulations because it is no longer necessary. This action is intended to facilitate increased participation by residents of CDQ communities in the groundfish fisheries in the Bering Sea and Aleutian Islands Management Area, and to support economic development in western Alaska. This action is necessary to promote the goals of the CDQ Program, and to promote the goals and objectives of the FMP, the Magnuson-Stevens Fishery Conservation and Management Act, and other applicable laws.
Submit comments on or before March 9, 2016.
You may submit comments on this document, identified by NOAA-NMFS-2015-0060, by any of the following methods:
•
•
Electronic copies of the Regulatory Impact Review/Initial Regulatory Flexibility Analysis/Environmental Assessment (RIR/IRFA/EA) prepared for this action (collectively the “Analysis”) is available from
Written comments regarding the burden-hour estimates or other aspects of the collection-of-information requirements contained in this proposed rule may be submitted to NMFS Alaska Region, P.O. Box 21668, Juneau, AK 99802, Attn: Ellen Sebastian, Records Officer; in person at NMFS Alaska Region, 709 West 9th Street, Room 420A, Juneau, AK; and by email to
Sally Bibb, 907-586-7389.
NMFS manages the groundfish fisheries of the Bering Sea and Aleutian Islands management area (BSAI) under the Fishery Management Plan for Groundfish of the Bering Sea and Aleutian Islands Management Area (FMP). The North Pacific Fishery Management Council (Council) prepared the FMP pursuant to the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act) (16 U.S.C. 1801,
The International Pacific Halibut Commission (IPHC) and NMFS manage fishing for Pacific halibut through regulations established under the authority of the Northern Pacific Halibut Act of 1982 (Halibut Act). The IPHC promulgates regulations governing the halibut fishery under the Convention between the United States and Canada for the Preservation of the Halibut Fishery of the Northern Pacific Ocean and Bering Sea (Convention). The IPHC's regulations are subject to approval by the Secretary of State with concurrence of the Secretary of Commerce (Secretary). NMFS publishes the IPHC's regulations as annual management measures pursuant to 50 CFR 300.62.
The Halibut Act, at sections 773c(a) and (b), provides the Secretary with general responsibility to carry out the Convention and the Halibut Act. In adopting regulations that may be necessary to carry out the purposes and objectives of the Convention and the Halibut Act, the Secretary is directed to consult with the Secretary of the department in which the U.S. Coast Guard is operating, currently the Department of Homeland Security.
The Halibut Act, at section 773c(c), also provides the Council with authority to develop regulations, including limited access regulations, that are in addition to, and not in conflict with, approved IPHC regulations. Regulations developed by the Council may be implemented by NMFS only after approval by the Secretary. The Council exercised this authority to allocate halibut to the CDQ Program as part of the Individual Fishing Quota (IFQ) Program for the commercial halibut and sablefish fisheries, codified at 50 CFR part 679, under the authority of section 773 of the Halibut Act and section 303(b) of the Magnuson-Stevens Act (16 U.S.C. 1853(b)).
The Council submitted Amendment 109 for review by the Secretary, and a notice of availability of Amendment 109 was published in the
If approved, this proposed rule would amend regulations governing the CDQ Program to support increased participation in the groundfish CDQ fisheries (primarily Pacific cod) by catcher vessels less than or equal to 46 ft LOA using hook-and-line gear. The proposed rule would exempt operators of registered catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA using hook-and-line gear to obtain and carry a License Limitation Program (LLP) license when groundfish CDQ fishing. This proposed rule also would reduce observer coverage requirements for catcher vessels less than or equal to 46 ft LOA when groundfish CDQ fishing and implement new in-season management and catch accounting requirements to properly account for the harvest of groundfish and halibut and the accrual of halibut prohibited species catch in these fisheries. This proposed rule is intended to facilitate increased participation by residents of CDQ communities in the BSAI groundfish CDQ fisheries and to support economic development in western Alaska. The proposed rule would benefit the six CDQ groups and the operators of the small hook-and-line catcher vessels that the CDQ groups authorize to fish on their behalf by reducing the costs of participating in the groundfish CDQ fisheries.
The following sections describe the fisheries and the current management programs affected by the proposed action: (1) Overview of the CDQ Program, (2) Regulatory Constraints on Local Small-Scale Groundfish CDQ Fisheries, (3) Need for the Proposed Action, and (4) The Proposed Rule.
The CDQ Program is an economic development program associated with federally managed fisheries in the BSAI. The purpose of the CDQ Program is to provide western Alaska communities with the opportunity to participate and invest in BSAI fisheries, to support economic development in western Alaska, to alleviate poverty and provide economic and social benefits for residents of western Alaska, and to achieve sustainable and diversified local economies in western Alaska. Regulations establishing the CDQ Program were first implemented in 1992. Congress amended the Magnuson-Stevens Act in 1996 through the Sustainable Fisheries Act (Pub. L. 104-297) to include specific provisions governing the CDQ Program. There are 65 communities eligible to participate in the CDQ Program. Each community is represented by one of six CDQ groups. The 65 eligible communities and the CDQ groups that collectively represent these 65 communities are identified in the Magnuson-Stevens Act at section 305(i)(1)(D) and in Table 7 to 50 CFR part 679.
The CDQ Program is a catch share program that allocates a portion of the
The CDQ Program allocates crab, groundfish, and halibut for harvest by the CDQ groups. The groundfish species allocated to the CDQ Program are pollock, Pacific cod, sablefish, yellowfin sole, Greenland turbot, arrowtooth flounder, rock sole, flathead sole, Pacific ocean perch, and Atka mackerel. A complete list of the amount of groundfish allocated to the CDQ Program can be found in the 2015 and 2016 annual harvest specifications final rule (80 FR 11919, March 5, 2015). The 2015 apportionments of crab, groundfish, and halibut to each CDQ group are listed in the annual CDQ Program allocation report at
One of the most effective ways the CDQ groups can meet the purposes of the CDQ Program is to use the CDQ allocations to create local small-scale commercial fisheries. Local small-scale CDQ fisheries directly provide opportunities for residents of the CDQ communities to earn income from the sale of the commercially harvested fish. Residents of CDQ communities participate almost exclusively in local small-scale fisheries. For purposes of this preamble, “local small-scale” means CDQ fisheries prosecuted by catcher vessels that are less than or equal to 46 ft LOA, using hook-and-line gear, and homeported or operated from CDQ communities. Catcher vessels less than or equal to 46 ft LOA are commonly used in the CDQ halibut fishery as described later in this preamble.
Not all species can be easily or readily harvested in local small-scale fisheries. Many groundfish and crab species are only effectively harvested in large industrial-scale fisheries due to the gear required (
Two species that are allocated to CDQ groups and that have been effectively harvested in local small-scale fisheries in the BSAI are halibut and Pacific cod. Both halibut and Pacific cod can be effectively harvested by small vessels using hook-and-line gear. Residents of CDQ communities commonly use hook-and-line gear because it is relatively inexpensive to purchase and maintain relative to other gear types such as trawl and pot gear, and can be operated on small vessels.
Currently, the majority of the local small-scale CDQ fisheries involve the harvest of the halibut CDQ allocations. By IPHC regulation, halibut must be harvested by hook-and-line gear. The halibut CDQ allocations typically are harvested by catcher vessels less than or equal to 46 ft LOA (14.0 m) using hook-and-line gear. As shown in Table 3-11 of the Analysis, the halibut CDQ fishing fleet ranged from 215 to 246 vessels from 2009 through 2013. Table 3-13 in the Analysis shows that in 2012 (the most recent year of complete data in the Analysis on the length of vessels harvesting halibut CDQ), 217 of the 239 catcher vessels fishing for halibut CDQ were less than or equal to 32 ft LOA, 9 were from 33 ft (10.1 m) LOA to 46 ft LOA, and only 13 vessels were greater than 46 ft LOA.
In recent years, the exploitable biomass of halibut in the BSAI has declined, particularly over the last four years. This has resulted in a declining halibut CDQ allocation as well. For example, the total halibut CDQ allocations were 2,128,000 pounds in 2011 and 797,080 pounds in 2015. The decrease in halibut CDQ allocations has resulted in decreasing opportunities for residents of CDQ communities to earn income important to themselves and their local economies. More information about the status of the halibut stock and halibut CDQ fisheries is in Sections 3.7 and 5.2 of the Analysis.
Pacific cod is an economically valuable groundfish species. It is valuable both to participants in the CDQ Program and to those harvesting Pacific cod outside of the CDQ Program (
In the non-CDQ Pacific cod fisheries, small hook-and-line catcher vessels have demonstrated an ability to harvest Pacific cod in the BSAI. For example, in 2014, five hook-and-line catcher vessels less than 60 ft (18.3 m) LOA harvested over 2,000 mt of Pacific cod in the non-CDQ Pacific cod fisheries in the Bering Sea (BS). (See Section 3.6.2 of the Analysis for additional detail on the non-CDQ Pacific cod fisheries.)
However, small catcher vessels have demonstrated very little current participation in the Pacific cod CDQ fisheries. As shown in Table 3-13 of the Analysis, of the approximately 240 catcher vessels fishing for halibut CDQ in 2012, only four of these catcher vessels harvested Pacific cod, and the amount harvested was very small (2 mt). Instead, the CDQ groups harvest most of their Pacific cod CDQ allocations with catcher/processors greater than 60 ft LOA using hook-and-line gear. These larger vessels can more efficiently harvest the CDQ allocations, can fish in the times and areas when and where Pacific cod are available, and can absorb the costs of the fisheries management and catch monitoring requirements associated with these fisheries. In addition, many of the CDQ groups own a portion of one or more hook-and-line catcher/processors, so in addition to receiving royalties for the lease of the Pacific cod CDQ, the CDQ group also earns a share of the profits from the catcher/processors. Finally, and most importantly for this proposed rule, there are regulatory constraints that limit the use of small catcher vessels in the groundfish CDQ fisheries. These constraints are described in more detail in the “LLP Requirements in the CDQ Fisheries” and “Observer Coverage Requirements in the CDQ Groundfish and Halibut Fisheries” sections of the preamble.
In addition to allocations of groundfish, halibut, and crab for harvest, the CDQ groups also receive annual allocations of certain BSAI PSC
The CDQ Program receives annual allocations of the BSAI PSC limits for halibut, Chinook salmon, non-Chinook salmon, red king crab,
The PSQ allocations in the CDQ Program are managed in the same manner as PSC limits in the non-CDQ fisheries. These requirements are described in regulations at §§ 679.32 and 679.7(d)(5). The halibut PSQs are transferable only among the CDQ groups. Operators of vessels groundfish fishing in the BSAI are prohibited from retaining Pacific halibut, unless the vessel operator is authorized to retain halibut CDQ or halibut IFQ. However, halibut often is incidentally caught when groundfish fishing because halibut can occur in the same areas and at the same time of year as the groundfish fisheries occur. The operator of a vessel engaged in directed fishing for groundfish in the BSAI must minimize catch of Pacific halibut prohibited species (see regulations at § 679.21(b)(2)). NMFS accrues estimates of halibut PSC to the halibut PSC limit or to a PSQ limit in all BSAI hook-and-line fisheries for Pacific cod, including the Pacific cod CDQ fisheries.
There are two regulatory constraints that limit the ability for CDQ groups to develop local small-scale groundfish fisheries, and more specifically local small-scale Pacific cod CDQ fisheries. These are (1) LLP requirements in the CDQ fisheries, and (2) observer coverage requirements in the CDQ groundfish and halibut fisheries. These constraints are described in the following sections of the preamble.
In 2000, NMFS established the LLP to limit the amount of fishing capacity relative to available fishery resources (63 FR 52642, October 1, 1998). The LLP limits the number, size, and specific operation of vessels fishing for groundfish in the BSAI, based on historical participation. With several exceptions noted below, a vessel is required to be named on an LLP license before it can be used to conduct directed fishing for “LLP groundfish” in the Gulf of Alaska or BSAI. LLP license requirements do not apply to vessels that directed fish only for halibut because halibut is not defined as an LLP groundfish species (see § 679.2). Vessels that are groundfish CDQ fishing in the BSAI are required to obtain and carry an LLP license (groundfish CDQ fishing is defined in § 679.2). LLP licenses are transferable. Vessel owners who were not initially issued an LLP license must obtain an LLP license through transfer from a current LLP license holder in order to directed fish for LLP groundfish.
There are three exceptions at § 679.4(k)(2) to the LLP license requirement that apply to vessels in the CDQ and non-CDQ fisheries in the BSAI:
• Vessels that do not exceed 32 ft (9.8 m) LOA;
• vessels that do not exceed 60 ft (18.3 m) LOA and that are using jig gear (but no more than 5 jig machines, 1 line per machine, and 15 hooks per line); and
• certain vessels constructed for, and used exclusively in, CDQ fisheries.
NMFS assigns endorsements for specific areas (
Therefore, specific to this proposed rule, catcher vessels less than or equal to 32 ft LOA that are groundfish CDQ fishing are not required to have an LLP license. Catcher vessels greater than 32 ft LOA that are using hook-and-line gear and groundfish CDQ fishing must have an LLP license endorsed by area, gear, and operation type, and have the appropriate MLOA designation. However, catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA are not required to have a Pacific cod species endorsement on their LLP license. Additional information on the LLP is available in the final rule implementing the LLP (63 FR 52642, October 1, 1998), and in subsequent amendments to the LLP.
The North Pacific Groundfish and Halibut Observer Program (Observer Program) provides the regulatory framework for NMFS-certified observers (observers) to collect information necessary for the conservation and management of the federally managed fisheries off Alaska. Regulations governing observer coverage (50 CFR part 679, subpart E) place all vessels and processors in the federally managed groundfish and halibut fisheries off Alaska into one of two observer coverage categories: (1) Full observer coverage, and (2) partial observer coverage. Additional information about observer coverage requirements and the vessel operator's responsibilities when required to carry an observer can be found at § 679.51(e) and in the preamble to the final rule implementing the restructured Observer Program (77 FR 70062, November 21, 2012).
Any catcher vessel participating in a catch share program with transferable PSC allocations is assigned to the full observer coverage category when the vessel is participating in these catch share programs. As described in an earlier section of this preamble, the CDQ Program is a catch share program with transferable PSC allocations. Therefore, NMFS assigns catcher vessels that participate in CDQ fisheries in which the catch of halibut accrues to the CDQ group's transferable halibut PSQ to the full observer coverage category. Relevant to this proposed rule, catcher vessels groundfish CDQ fishing using hook-and-line gear, including those directed fishing for Pacific cod CDQ, are in the full observer coverage category because the discard of halibut by these vessels accrues to the CDQ group's halibut PSQ.
NMFS assigns catcher vessels that are halibut CDQ fishing or sablefish CDQ fishing with fixed gear to the partial observer coverage category, as it does for catcher vessels groundfish CDQ fishing with pot or jig gear. These catcher vessels are required to have an observer on board the vessel if selected for observer coverage (see § 679.51(a)(1)). These catcher vessels are in the partial observer coverage category because the catch of prohibited species in these fisheries does not accrue to a PSQ.
Full observer coverage requirements can impose significant costs on the owners of vessels that are groundfish CDQ fishing, particularly owners of small vessels, such as those that are less
In October 2013, the Council received a proposal from the representatives of all six of the CDQ groups to revise certain Federal regulations that restrict the ability of fishermen in CDQ communities to harvest allocations of Pacific cod CDQ with small hook-and-line catcher vessels. In particular, representatives for the CDQ groups identified LLP license and full observer coverage regulations as limitations on the ability of CDQ community fishermen to retain Pacific cod CDQ when participating in the CDQ fisheries. In addition, the CDQ groups reported that recent declines in halibut CDQ allocations could prevent the CDQ Program from meeting its economic development objectives, and the ability to develop a local small-scale Pacific cod CDQ fishery would help to offset the lost halibut harvesting and processing opportunities in the CDQ communities. In response, the Council reviewed and developed a series of analyses that resulted in this proposed action.
The Council recommended its preferred alternative in February 2015. The Council's preferred alternative would (1) exempt operators of registered catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA using hook-and-line gear from the requirement to obtain and carry an LLP license when groundfish CDQ fishing; (2) place catcher vessels less than or equal to 46 ft LOA using hook-and-line gear in the partial observer coverage category when they are groundfish CDQ fishing; (3) allow halibut caught by operators of catcher vessels less than or equal to 46 ft LOA using hook-and-line gear when groundfish CDQ fishing to accrue as either halibut CDQ, halibut IFQ, or halibut PSC, on a trip-by-trip basis; and (4) implement new in-season management and catch accounting procedures to properly account for the harvest of groundfish and halibut and the accrual of halibut PSC by operators of catcher vessels less than or equal to 46 ft LOA using hook-and-line gear when halibut or groundfish CDQ fishing. Additional details about the specific management measures NMFS proposes to implement the Council's preferred alternative are described below in the section titled “The Proposed Rule.”
The Council's preferred alternative is intended to provide a regulatory structure for the harvest of groundfish CDQ that provides opportunities for the small catcher vessels that fish on behalf of a CDQ group to retain additional Pacific cod and other groundfish in the halibut CDQ fishery, or to develop separate Pacific cod or other groundfish CDQ fisheries without triggering LLP license and full observer coverage requirements. The Council's preferred alternative also is intended to provide additional fishing opportunities to small catcher vessel operators in CDQ communities who have had reduced harvest opportunities due to lower halibut abundance and the resulting lower halibut CDQ allocations. This proposed action is intended to provide the regulatory flexibility necessary for the CDQ groups to develop diversified local small-scale halibut and groundfish fisheries.
The Council determined that a new LLP exemption for registered catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA using hook-and-line gear when groundfish CDQ fishing was necessary to encourage the retention and sale of groundfish CDQ in the halibut fisheries and to encourage the development of directed fisheries for groundfish CDQ by vessel operators delivering catch to processors located in CDQ communities. Exemption from the LLP would remove a barrier created by the lack of LLP licenses available for small hook-and-line catcher vessels fishing on behalf of a CDQ group. The Council determined and NMFS agrees that this limited exemption to the LLP license requirements would not undermine the objectives of the LLP because it would apply only to registered small catcher vessels when groundfish CDQ fishing. Because the CDQ groups receive specific harvest allocations, the Council determined and NMFS agrees that providing a limited exemption to these registered catcher vessels would not result in increased harvests overall in the BSAI groundfish fisheries, or contribute to a “race for fish” among fishery participants.
As noted earlier in this preamble, there are approximately 240 vessels that fish for halibut out of CDQ communities. Under current regulations, operators of vessels that are greater than 32 ft LOA are prohibited from also conducting directed fishing for CDQ groundfish or non-CDQ groundfish when they are halibut CDQ or halibut IFQ fishing unless they have an LLP license with the necessary endorsements. The Council recommended that the exemption apply only to catcher vessels that are less than or equal to 46 ft LOA because approximately 95 percent of the approximately 240 catcher vessels currently active in halibut CDQ fisheries are within this size class. In addition, the CDQ groups recommended the 46-ft-LOA threshold because the largest vessel that is owned by a resident of a CDQ community that participates in the halibut CDQ fisheries is 46 ft LOA. Therefore, although the Council recognized that there are catcher vessels greater than 46 ft LOA fishing for halibut CDQ that do not have LLPs, the focus of this proposed action is on the smaller vessels because those vessels generally are owned and operated by residents of the CDQ communities and fish out of those communities.
Nine of the approximately 240 catcher vessels that fish for halibut out of the CDQ communities are greater than 32 ft LOA and less than or equal to 46 ft LOA. Only two of these nine catcher vessels are already assigned LLP licenses. Currently, all of the LLP licenses with the appropriate MLOA, gear endorsement (
The Council also recommended that each CDQ group register any catcher vessel eligible for the LLP license exemption with NMFS in order for the exemption to apply. The CDQ vessel registration list would clearly identify those eligible vessels that are exempt from the LLP license requirements. It is important to note that the LLP license exemption would not apply until an eligible vessel is successfully registered by a CDQ group representative. The Council also recommended that an LLP exemption letter be issued to each
The Council recommended placing the hook-and-line catcher vessels less than or equal to 46 ft LOA that are groundfish CDQ fishing in the partial observer coverage category to remove a significant financial and operational barrier to further development of the local small-scale groundfish CDQ fisheries. In making this recommendation, the Council recognized that it is likely that few CDQ small vessels would be required to carry an observer under the existing deployment strategy and deployment rates for vessel in the partial observer coverage category (see Section 3.12 of the Analysis for additional detail on observer deployment). However, the Council determined and NMFS agrees that the benefits that would come with increased participation in local small-scale groundfish CDQ fisheries would justify the moving these vessels from full observer coverage to partial observer coverage. Additionally, the Council and NMFS determined that NMFS could adequately account for harvests and discards in these local small-scale groundfish CDQ fisheries with certain modifications to the catch accounting procedures.
To establish effective catch accounting for hook-and-line catcher vessels less than or equal to 46 ft LOA that are groundfish CDQ fishing, the Council recommended that NMFS modify catch accounting procedures as described below in the “Catch Accounting and Fisheries Management” section of the preamble.
When the halibut fishery is open, the Council's preferred alternative would allow the CDQ groups to decide on a trip-by-trip basis whether a groundfish CDQ fishing trip by a hook-and-line catcher vessel less than or equal to 46 ft LOA would be supported by halibut CDQ, halibut IFQ, or by halibut PSC. When the halibut fishery is closed, the CDQ groups could conduct groundfish CDQ fishing by hook-and-line catcher vessels less than or equal to 46 ft LOA supported by halibut PSC. The Council determined and NMFS agrees that the allowance for trip-by-trip accounting would provide the maximum flexibility for the CDQ groups and vessel operators to increase the harvest of Pacific cod CDQ as part of a halibut CDQ or halibut IFQ fishery, or as a separate Pacific cod fishery in which halibut PSC would accrue. This allowance is consistent with the purpose of the proposed action. NMFS would manage the removals of halibut and debit them from the proper account as described in “The Proposed Rule” section of this preamble.
The Council determined and NMFS agrees that the local small-scale groundfish CDQ fisheries would be managed by NMFS with in-season fishery closures and a separate component of a CDQ group's halibut PSQ that would be called the “small catcher vessel halibut PSC limit.” The determination of whether halibut PSC would accrue to the small catcher vessel halibut PSC limit for the groundfish CDQ landing would depend on the presence or absence of halibut in the landing. As long as the halibut fishery is open and at least one halibut is reported as halibut CDQ or halibut IFQ in the groundfish CDQ landing, NMFS would not accrue any estimates of halibut PSC from this landing to the CDQ group's small catcher vessel halibut PSC limit. When the halibut fishery is closed, or if the halibut fishery is open and no halibut are reported in the landing, NMFS would accrue an estimate of halibut PSC to the CDQ group's small catcher vessel halibut PSC limit. Once a vessel operator retains one halibut, he or she would be required to retain all legal-size halibut caught for the remainder of that fishing trip as either halibut CDQ or halibut IFQ.
The Council and NMFS determined that establishing small catcher vessel halibut PSC limits for each CDQ group fishing with small hook-and-line catcher vessels would meet two important objectives. First, it would maintain the precedent the Council has set to require full observer coverage for any catcher vessels in catch share programs with transferable PSC allocations while allowing small hook-and-line catcher vessels to fish for groundfish CDQ without being subject to full observer coverage. Second, it would establish a method for assessing halibut PSC for the small hook-and-line catcher vessels based on the same methods used for other small hook-and-line catcher vessels active in the non-CDQ groundfish fisheries. More information about the management of the small vessel groundfish CDQ fisheries is in the section below titled “The Proposed Rule.”
Under the Council's preferred alternative, all other regulations not specifically exempted or modified would continue to apply to the small hook-and-line catcher vessels when groundfish CDQ fishing. These include area closures and vessel monitoring system (VMS) requirements that apply to all hook-and-line catcher vessels directed fishing for CDQ and non-CDQ Pacific cod. Additional detail on regulations that are currently applicable to small hook-and-line catcher vessels is provided in Section 2.1 of the Analysis and is not repeated here.
The following paragraphs describe the provisions of the proposed rule. The proposed rule would revise regulations at 50 CFR part 679 to implement Amendment 109 and the Council's preferred alternative to: (1) Exempt registered catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA using hook-and-line gear from the requirement to obtain and carry an LLP license when groundfish CDQ fishing; (2) add fishery management and monitoring requirements for the small hook-and-line catcher vessels to § 679.32(c); and (3) place catcher vessels less than or equal to 46 ft LOA using hook-and-line gear into the partial observer coverage category when groundfish CDQ fishing. In addition to these changes, the proposed rule would remove an unnecessary cross reference table for observer coverage from § 679.51(f).
The current LLP exemptions are codified at § 679.4(k)(2). The proposed rule would add a new paragraph (vi) to § 679.4(k)(2) to establish a new LLP exemption for registered catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA using hook-and-line gear when groundfish CDQ fishing. The operators of catcher vessels eligible for
The proposed rule would establish the requirements for the NMFS online CDQ vessel registration system (“the CDQ vessel registration system”) at paragraph (m) of § 679.5. The CDQ group representative would be required to register each eligible catcher vessel for exemption from the LLP license requirements through the CDQ vessel registration system. The CDQ group representative would be required to log into the CDQ vessel registration system using the CDQ group's existing NMFS ID and password and provide the information required on the computer screen. NMFS would add each vessel successfully registered to the CDQ vessel registration list on the NMFS Alaska Region Web site at
The CDQ group representative could add eligible catcher vessels to the CDQ vessel registration list at any time during the groundfish fishing year (January 1 to December 31); there would be no deadline for vessel registration with NMFS. Because registered vessels would be required to have a legible copy of the LLP exemption letter described below on board the vessel before the vessel operator starts groundfish CDQ fishing, the CDQ group representative and the vessel operator would have to allow for sufficient time to complete the registration process prior to the start of groundfish CDQ fishing by the vessel.
With each successful registration, the CDQ vessel registration system would provide the CDQ group representative with an LLP exemption letter documenting that the vessel is eligible for the LLP exemption when groundfish CDQ fishing. The CDQ group representative would be responsible for providing a copy of the LLP exemption letter to the vessel operator. The vessel operator would be required to maintain a legible copy of the LLP exemption letter on board the named vessel at all times when that vessel is groundfish CDQ fishing. NMFS would not provide the LLP exemption letter directly to vessel operators.
The LLP exemption letter also would provide printable confirmation to the CDQ group of a successfully completed vessel registration. Once registered, a vessel would remain on the CDQ vessel registration list until removed by a CDQ group. The proposed rule does not include a requirement that the CDQ groups re-register vessels annually.
A CDQ group representative would have the ability to remove a vessel from the CDQ vessel registration list at any time by logging into the CDQ vessel registration system and following the applicable instructions. In removing a vessel from the CDQ vessel registration list, the CDQ group representative would be required to certify (1) that the vessel operator had been given notice by the CDQ group that the vessel was going to be removed from the list, and (2) that the vessel operator was not groundfish CDQ fishing at the time of removal. The CDQ vessel registration system would provide a printable confirmation that a vessel had been removed from the CDQ vessel registration list. Once a vessel is removed from the CDQ vessel registration list, that vessel would no longer be exempt from the LLP requirements, even if the operator was still in possession of the LLP exemption letter. The proposed rule would not require a CDQ group representative to remove registered vessels when they are participating in a non-CDQ fishery.
In order to receive the exemption from the LLP license requirements, both active registration through the CDQ vessel registration system and a legible copy of the LLP exemption letter on board the vessel would be required. To further clarify the vessel operator's responsibility, the proposed rule would add a new prohibition at § 679.7(d)(8) to prohibit the operator of a vessel eligible for the LLP exemption from conducting groundfish CDQ fishing without having a legible copy of the LLP exemption letter issued to a CDQ group for that vessel on board the vessel. In addition, the proposed rule would add a new prohibition at § 679.7(d)(9) to prohibit a CDQ group representative from removing a vessel from the CDQ vessel registration list without first providing notice to the operator of the registered vessel that the vessel is being removed from the CDQ vessel registration list, or when the vessel is groundfish CDQ fishing.
The proposed rule would create a new paragraph (c)(3)(iii) in § 679.32 for the catch accounting and fishery monitoring requirements that would apply to catcher vessels less than or equal to 46 ft LOA using hook-and-line gear when groundfish CDQ fishing and to the CDQ groups authorizing these vessels. Current regulations at § 679.32(c)(3)(i)(D) and (c)(3)(ii)(D) would continue to apply to catcher vessels greater than 46 ft LOA using hook-and-line gear when groundfish CDQ fishing.
The proposed rule would establish catch accounting procedures that provide CDQ groups and vessel operators with the opportunity to retain halibut CDQ or halibut IFQ when groundfish CDQ fishing. If the vessel operator is relying on halibut CDQ from a CDQ group to support the retained catch of legal-size halibut during a fishing trip, the CDQ group would be required to provide adequate halibut CDQ to this vessel operator to account for all the legal-size halibut caught by the vessel during the entire fishing trip. A CDQ group's halibut PSQ would not be reduced if halibut is present in the landing. Landed halibut CDQ or halibut IFQ would accrue to the account balance of the permit holder identified by the processor in the landing report based on the permits held by the vessel operator or persons on board the vessel.
The operator of a hook-and-line catcher vessel less than or equal to 46 ft LOA who retains any halibut CDQ or halibut IFQ during the groundfish CDQ fishing trip would be required to retain all legal-size halibut caught during that fishing trip. The Council and NMFS determined that this regulatory provision is necessary to ensure proper accounting for halibut and to reduce halibut discards in the small vessel groundfish CDQ fishery. In this situation, NMFS would assume that the vessel operator retained all legal-size halibut and that the only halibut released from the fishing gear would be sub-legal-size halibut. NMFS would continue to account for sub-legal-size halibut as wastage associated with the halibut fishery and it would not accrue to any halibut PSC limit. Under the proposed rule, as long as at least one halibut was included in the groundfish CDQ landing, NMFS would not accrue any estimates of halibut PSC from the small vessel groundfish CDQ fisheries to the CDQ group's halibut PSQ or to any component of the BSAI halibut PSC limit.
If no halibut are included in a groundfish CDQ landing, NMFS would accrue an estimate of halibut PSC to the CDQ group's small catcher vessel halibut PSC limit (described below). NMFS would estimate the halibut PSC associated with these types of groundfish CDQ fishing trips using halibut PSC rates as calculated by NMFS, and apply the halibut PSC rates when halibut fishing is closed or when halibut fishing is open but no halibut are included in a landing.
Under the proposed rule, NMFS would create a new quota category available to each CDQ group called the “small catcher vessel halibut PSC limit.” If a CDQ group wants to have a
With the exception of sablefish CDQ fishing, which will continue to be managed under § 679.32(c)(1), the proposed rule would prohibit groundfish CDQ fishing by catcher vessels less than or equal to 46 ft LOA using hook-and-line gear unless NMFS publishes notification in the
If NMFS determines that a CDQ group's small catcher vessel halibut PSC limit has been or will be reached, NMFS would issue a notice in the
Even with conservative management, it is possible that a small catcher vessel halibut PSC limit could be exceeded due to the high degree of variability in halibut PSC rates that can occur in hook-and-line fisheries. If NMFS is unable to close a CDQ group's small catcher vessel groundfish CDQ fishery before it exceeds the amount of halibut PSC allocated to the small catcher vessel halibut PSC limit, NMFS would not consider this a violation, and NMFS would not require the CDQ group to transfer an amount of halibut PSQ needed to cover the negative balance. However, the proposed rule would allow a CDQ group to voluntarily choose to transfer additional halibut PSQ to bring the balance of its small catcher vessel halibut PSC limit to zero.
If a CDQ group's small catcher vessel halibut PSC limit has a negative balance at the end of the groundfish fishing year (December 31), and if the CDQ group has remaining halibut PSQ on that date, NMFS would transfer an amount of halibut PSQ into the CDQ group's small catcher vessel halibut PSC limit to bring the balance of the small catcher vessel halibut PSC limit to zero. NMFS would make this administrative transfer only after all fishing by a CDQ group is completed for the year, after data from the fishing year is finalized, and if the CDQ group had sufficient remaining halibut PSQ.
The CDQ Program currently receives an allocation of 393 mt of halibut PSC, which is further allocated among the CDQ groups in annual halibut PSQ allocations to individual CDQ groups that range from 25 mt to 135 mt. Between 2010 and 2014, none of the CDQ groups fully used their halibut PSQ, and all CDQ groups had remaining halibut PSQ at the end of the year. Therefore, NMFS has determined that, should an administrative transfer be warranted, a CDQ group will likely have sufficient halibut PSQ to accommodate the transfer. However, if a CDQ group does not have a sufficient amount of halibut PSQ to cover a negative balance in the CDQ group's small catcher vessel halibut PSC limit, NMFS would not undertake an administrative transfer and there would be no regulatory or compliance consequences to the CDQ group.
The proposed rule also would permit a CDQ group to transfer halibut from its small catcher vessel halibut PSC limit back to the CDQ group's halibut PSQ. In reviewing a request to transfer halibut from the small catcher vessel halibut PSC limit back to the CDQ group's halibut PSQ, NMFS would consider the status of CDQ fisheries through the end of the year and anticipated halibut PSC rates for any remaining groundfish CDQ fishing by vessels managed under the small catcher vessel halibut PSC limit for the requesting CDQ group.
The proposed rule would add paragraph (a)(1)(i)(D) to § 679.51 and revise § 679.51(a)(2)(i)(C)(
Under current regulations, the owners or operators of vessels in the partial observer coverage category are placed in an observer selection pool based on the requirements of the Annual Deployment Plan (ADP). Since implementation of the ADP process in 2013, vessels less than 40 ft. (12.2 m) LOA have been placed in the “no selection pool.” These vessels are not required to carry observers or register fishing trips with NMFS. Vessels 40 ft LOA or greater are in the “trip selection pool” and must log all of their fishing trips in the Observer Declare and Deploy System (ODDS). This is an online system for registering fishing trips and receiving information about whether a particular trip is selected for observer coverage. If selected for observer coverage, the catcher vessel is required to carry an observer. Operators of vessels selected for observer coverage are required to comply with all vessel responsibilities in § 679.51(e)(1). More information about logging trips in ODDS is on the NMFS Alaska Region Web site under “Frequently Asked Questions” about the Observer Program (
Hook-and-line catcher vessels engaged in halibut CDQ fishing have been in the partial observer coverage category since 2013. Operators of vessels 40 ft LOA or greater have been logging halibut CDQ fishing trips and should be familiar with the requirements for partial observer coverage. Most of the small hook-and-line catcher vessels that are expected to participate in separate Pacific cod CDQ fisheries under the proposed action are owned or operated by people who have participated in the halibut CDQ fisheries (see Section 3.7 of the Analysis). Therefore, the requirements and procedures for partial observer coverage should be familiar to them. If a vessel operator retains groundfish CDQ during a halibut CDQ fishing trip, no additional trips will need to be logged in ODDS. If a vessel operator makes separate fishing trips to target Pacific cod CDQ, the vessel operator would be required to log these new fishing trips in ODDS, and to carry an observer if selected to do so.
The proposed rule would remove the table in § 679.51(f) that summarizes the observer coverage requirements for different management programs and industry sectors. Prior to Observer Program Restructuring (77 FR 70062, November 21, 2012), this table was located at the beginning of subpart E as table of contents or guide to observer coverage requirements. However, with the reorganization of observer coverage requirements in the 2012 rule and the placement of this table at the end of § 679.51, it no longer serves its previous function as a table of contents for the section. Therefore, NMFS proposes to remove the table.
Pursuant to sections 304(b)(1)(A) and 305(d) of the Magnuson-Stevens Act, the NMFS Assistant Administrator has determined that this proposed rule is consistent with Amendment 109 to the FMP, other provisions of the Magnuson-Stevens Act, and other applicable law, subject to further consideration after public comment.
This proposed rule has been determined to be not significant for purposes of Executive Order 12866.
An initial regulatory flexibility analysis (IRFA) was prepared, as required by section 603 of the Regulatory Flexibility Act (RFA). The IRFA describes the economic impact this proposed rule, if adopted, would have on small entities. A further description of the action, why it is being considered, and the legal basis for this action are contained earlier in the preamble to this proposed rule. A copy of the IRFA is available from NMFS (see
The proposed action would directly regulate two classes of small entities: (1) The six CDQ groups, which are non-profit corporations that represent the 65 western Alaska communities that are eligible to participate in the CDQ Program; and (2) the owners and operators of small hook-and-line catcher vessels who are authorized by a CDQ group to harvest groundfish or halibut CDQ allocations.
The RFA recognizes and defines three kinds of small entities: (1) Small businesses, (2) small non-profit organizations, and (3) small government jurisdictions. The CDQ groups are considered small entities due to their status as non-profit corporations. According to Section 1.2.1 of the Analysis, the six CDQ groups had total revenues of approximately $311.5 million in 2011, primarily from royalties on the lease of pollock CDQ allocations. Between 1992 and 2011, the CDQ groups accumulated net assets worth approximately $803 million, including ownership of small local processing plants, catcher vessels, and catcher/processors that participate in the groundfish, crab, salmon, and halibut fisheries.
The Small Business Administration has established size standards for all major industry sectors in the United States. A business primarily involved in finfish harvesting is classified as a small business if it is independently owned and operated, is not dominant in its field of operation (including its affiliates), and has combined annual gross receipts not in excess of $20.5 million, for all its affiliated operations worldwide.
It is difficult to predict how many small hook-and-line catcher vessels may participate in the future under the proposed action because no catcher vessels less than or equal to 46 ft LOA using hook-and-line gear currently are conducting directed fishing for groundfish CDQ. The best estimate of the upper bound of the number of future participants in the small catcher vessel Pacific cod CDQ fisheries is the maximum of 278 vessels less than or equal to 46 ft LOA that participated in the halibut CDQ fisheries from 2000 to 2013. NMFS assumes that all of the vessels that could be directly regulated by this action would be small entities based on estimated revenues of less than $20.5 million for all vessels and their known affiliations.
The proposed action contains three new reporting and recordkeeping requirements that affect small entities. First, each CDQ group that authorizes catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA using hook-and-line gear to fish for groundfish CDQ with an exemption from the LLP would be required to register the vessel in an online CDQ vessel registration system developed and maintained by NMFS. All six CDQ groups would then be subject to the vessel registration requirement if they had vessels participating.
Second, operators of registered catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA using hook-and-line gear that would be exempt from the LLP license requirements would be required to maintain a legible copy of an LLP exemption letter on board the vessel at all times when groundfish CDQ fishing. The LLP exemption letter would be generated through the CDQ vessel registration system when a CDQ group registered an eligible vessel. Each CDQ group representative would be required to provide this letter to the vessel operator. All six CDQ groups and all vessel operators could be subject to this requirement.
Third, small catcher vessels fishing for groundfish CDQ under the proposed action would be placed in the partial observer coverage category. Vessels subject to observer coverage are determined annually through the Observer Program's Annual Deployment Plan (ADP). Since inception of the ADP process in 2013, vessels less than 40 ft. LOA have been placed in the “no selection pool” and have had no additional reporting or recordkeeping requirements. Vessels 40 ft LOA or greater are in the “trip selection pool” and must log all of their fishing trips in the Observer Declare and Deploy System (ODDS). This is an online system for registering fishing trips and receiving information about whether a particular trip is selected for observer coverage.
Vessels between 40 ft LOA and 46 ft LOA already log their halibut CDQ and halibut IFQ fishing trips in ODDS. Therefore, if these vessels are combining groundfish CDQ fishing with halibut CDQ or halibut IFQ fishing, they would not incur any additional reporting requirements associated with placement in the partial observer coverage category because the halibut trips already are in partial observer coverage. However, if any of these vessels starts fishing for groundfish CDQ separate from their halibut CDQ or halibut IFQ fishing trips, then those additional fishing trips would be required to be logged in ODDS. The cost of logging trips in ODDS would represent an additional cost associated with the new small catcher vessel groundfish CDQ fisheries.
The RFA requires identification of any significant alternatives to the proposed rule that accomplish the stated objectives of the proposed action, consistent with applicable statutes, and that would minimize any significant economic impact of the proposed rule on small entities. As noted in the IRFA, the proposed action is expected to create a net benefit for the directly regulated small entities. The benefits of the proposed action are expected to outweigh the reporting, recordkeeping, and other compliance costs described in the previous section.
The Council considered a status quo alternative (Alternative 1), and two action alternatives (Alternatives 2 and 3) to the preferred alternative (Alternative 4). Neither Alternative 2 nor 3 would have provided more benefits to the
Under Alternative 2, the maximum retainable amount (MRA) of Pacific cod in the halibut CDQ fisheries would have been increased so the operators of the small hook-and-line vessels could retain more Pacific cod when halibut CDQ fishing and still be considered directed fishing for halibut rather than directed fishing for Pacific cod. Alternative 2 was considered because the more costly LLP license requirements, observer coverage requirements, and VMS requirements do not apply to vessels halibut CDQ fishing in the BSAI (except that the VMS requirements apply to vessels halibut fishing in the Aleutian Islands). Increasing the MRAs for Pacific cod when halibut CDQ fishing would allow the small vessels to retain more Pacific cod without triggering requirements that apply to vessels directed fishing for Pacific cod. The Council did not select this alternative because the preferred alternative would accomplish a similar outcome to Alternative 2 without creating a situation where vessels with the same catch composition were defined as fishing for halibut in the CDQ fisheries and fishing for Pacific cod in the non-CDQ fisheries. Alternative 2 would have increased monitoring and enforcement costs relative to the preferred alternative.
The Council also considered Alternative 3, which would have created a new type of LLP license specific to the small CDQ vessels. This approach was an alternative to providing an exemption to the LLP, as is proposed in the preferred alternative. However, this alternative would not necessarily have resulted in a reduction in reporting, recordkeeping, and compliance costs in comparison to the proposed action. Issuing a new CDQ LLP license would have required applications to NMFS and the issuance of a CDQ LLP license with certain conditions. Alternative 3 would have increased costs relative to the preferred alternative.
No relevant Federal rules have been identified that would duplicate or overlap with the proposed action.
This proposed rule contains collection-of-information requirements subject to review and approval by the Office of Management and Budget (OMB) under the Paperwork Reduction Act (PRA). These requirements have been submitted to OMB for approval. The information collections are presented by OMB control number. OMB Control No. 0648-0269
Public reporting burden for CDQ Vessel Registration to add or remove vessels online that are exempt from the LLP license requirements is estimated to average five minutes per individual response and five minutes for maintenance of the LLP exemption letter on board a vessel that is groundfish CDQ fishing. The Groundfish/Halibut CDQ and Prohibited Species Quota (PSQ) Transfer Request is mentioned in this proposed rule, but no changes occur in the individual response for each requirement. OMB Control No. 0648-0318
The Observer Declare and Deploy System (ODDS) is mentioned in this proposed rule, but the individual response for each requirement is not changed. OMB Control No. 0648-0334
The individual response for each requirement of the LLP mentioned in this rule is not changed.
Public comment is sought regarding: Whether this proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; the accuracy of the burden estimate; 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, including through the use of automated collection techniques or other forms of information technology. Send comments on these or any other aspects of the collection of information to NMFS at the
Notwithstanding any other provision of the law, no person is required to respond to, and no person shall be subject to penalty for failure to comply with, a collection of information subject to the requirements of the PRA, unless that collection of information displays a currently valid OMB control number.
Alaska, Fisheries, Reporting and recordkeeping requirements.
For the reasons set out in the preamble, 50 CFR part 679 is proposed to be amended as follows:
16 U.S.C. 773
The addition to read as follows:
(k) * * *
(2) * * *
(vi) The operator of a catcher vessel that is greater than 32 ft (9.8 m) LOA, that does not exceed 46 ft (14.0 m) LOA, and that is registered by a CDQ group following the procedures described in § 679.5(m) may use hook-and-line gear to conduct groundfish CDQ fishing without a groundfish license.
(m)
(2)
(3)
(4)
(d) * * *
(8) For an operator of a catcher vessel greater than 32 ft (9.8 m) LOA and less than or equal to 46 ft (14.0 m) LOA using hook-and-line gear and that is registered by a CDQ group under § 679.5(m), to conduct groundfish CDQ fishing without a legible copy of the LLP exemption letter issued to a CDQ group for that vessel on board the vessel.
(9) For a CDQ group representative, to remove a vessel from the CDQ vessel registration list under § 679.5(m)(4) without first providing notice to the operator of the registered vessel that the vessel is being removed from the CDQ vessel registration list or when the vessel operator is groundfish CDQ fishing.
(c) * * *
(3) * * *
(i) * * *
(D)
(ii) * * *
(D)
(iii)
(B)
(
(
(
(C)
(
(
(
(a) * * *
(1) * * *
(i) * * *
(D) A catcher vessel less than or equal to 46 ft LOA using hook-and-line gear when groundfish CDQ fishing under § 679.32(c)(3)(iii).
(2) * * *
(i) * * *
(C) * * *
(
Animal and Plant Health Inspection Service, USDA.
Notice of meeting.
This is a notice to inform the public of an upcoming meeting of the Secretary's Advisory Committee on Animal Health. The meeting is being organized by the Animal and Plant Health Inspection Service to discuss matters of animal health.
The meeting will be held February 23, 24, and 25, 2016, from 9 a.m. to 5 p.m. central standard time.
The meeting will be held at the Marriott Dallas/Addison Quorum, 14901 Dallas Parkway, Dallas, TX 75254.
Mrs. R.J. Cabrera, Designated Federal Officer, VS, APHIS, 4700 River Road Unit 34, Riverdale, MD 20737; phone (301) 851-3478; email:
The Secretary's Advisory Committee on Animal Health (the Committee) advises the Secretary of Agriculture on matters of animal health, including means to prevent, conduct surveillance on, monitor, control, or eradicate animal diseases of national importance. In doing so, the Committee will consider public health, conservation of natural resources, and the stability of livestock economies.
Tentative topics for discussion at the meeting include:
• Chronic Wasting Disease Program;
• One Health
○ Zoonotic Diseases,
○ National List of Reportable Animal Diseases, and
○ U.S. Department of Agriculture Antimicrobial Resistance Action Plan;
• Scrapie Program;
• Foot and Mouth Disease Vaccine Availability;
• Emerging Disease Response; and
• Comprehensive Integrated Animal Health Surveillance.
A final agenda will be posted on the Committee Web site by February 15, 2016.
Those wishing to attend the meeting in person must complete a brief registration form by clicking on the “SACAH Meeting Sign-up” button on the Committee's Web site (
Due to time constraints, members of the public will not have an opportunity to participate in the Committee's discussions. However, questions and written statements for the Committee's consideration may be submitted up to 5 working days before the meeting. They may be sent to
This notice of meeting is given pursuant to section 10 of the Federal Advisory Committee Act (5 U.S.C. App. 2).
Food Safety and Inspection Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 and Office of Management and Budget (OMB) regulations, the Food Safety and Inspection Service (FSIS) is announcing its intention to renew the approved information collection regarding the importation and transportation of meat, poultry, and egg products. The approval for this information collection will expire on May 31, 2016.
Submit comments on or before April 8, 2016.
FSIS invites interested persons to submit comments on this information collection. Comments may be submitted by one of the following methods:
•
•
•
Gina Kouba, Paperwork Reduction Act Coordinator, Food Safety and Inspection Service, USDA, 1400 Independence Avenue SW., Room 6065, South Building, Washington, DC 20250; (202) 720-5627.
FSIS is planning to request a renewal of this approved information collection because it is due to expire on May 31, 2016. This information collection includes (1) foreign inspection certificates required by FSIS to export meat, poultry, and egg products to the United States (9 CFR 327.2 and 381.196); (2) documentation required by FSIS for official import establishments to pre-stamp imported product with the inspection legend before reinspection is complete (9 CFR 327.10(d) and 381.204(f)); and (3) documentation required to transport meat and poultry shipments under seal (FSIS Form 7350-1, Request and Notice of Shipment of Sealed Meat and Poultry) (9 CFR 325.5).
(1) Foreign countries that wish to export meat, poultry, and egg products to the United States must establish eligibility to do so by putting in place inspection systems are “equivalent to” the U.S. inspection system (9 CFR 327.2 and 381.196) and by annually certifying that they continue to do so. Meat, poultry, and egg products intended for importation into the U.S. must be accompanied by an inspection certificate signed by an official of the foreign government responsible for the inspection and certification of the product (9 CFR 327.4, 381.197, and 590.915).
(2) Import establishments that wish to pre-stamp imported product with the inspection legend before FSIS inspection is complete must submit a letter to FSIS that explains and requests approval for the establishment's pre-stamping procedure (9 CFR 327.10(d) and 381.204(f)).
(3) Unless accounted for in an establishment's HACCP plan, meat and poultry products that do not bear the mark of inspection and that are to be shipped from one official establishment to another for further processing must be transported under USDA seal to prevent such unmarked product from entering into commerce (9 CFR 325.5). To track product shipped under seal, FSIS requires the shipping establishment to complete FSIS Form 7350-1, which identifies the type, amount, and weight of the product.
FSIS has made the following estimates on the basis of an information collection assessment.
Copies of this information collection assessment can be obtained from Gina Kouba, Paperwork Reduction Act Coordinator, Food Safety and Inspection Service, USDA, 1400 Independence SW., Room 6077, South Building, Washington, DC 20250, (202) 690-6510.
Responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public record.
Public awareness of all segments of rulemaking and policy development is important. Consequently, FSIS will announce this
FSIS also will make copies of this publication available through the FSIS Constituent Update, which is used to provide information regarding FSIS policies, procedures, regulations,
No agency, officer, or employee of the USDA shall, on the grounds of race, color, national origin, religion, sex, gender identity, sexual orientation, disability, age, marital status, family/parental status, income derived from a public assistance program, or political beliefs, exclude from participation in, deny the benefits of, or subject to discrimination any person in the United States under any program or activity conducted by the USDA.
To file a complaint of discrimination, complete the USDA Program Discrimination Complaint Form, which may be accessed online at
Send your completed complaint form or letter to USDA by mail, fax, or email:
Persons with disabilities who require alternative means for communication (Braille, large print, audiotape, etc.), should contact USDA's TARGET Center at (202) 720-2600 (voice and TDD).
Forest Service, USDA.
Notice.
This notice lists the newspapers that Ranger Districts, Forests, and the Regional Office of the Alaska Region will use to publish legal notices of the opportunity to object to proposed projects and activities implementing land and resource management plans, including hazardous fuel reduction projects authorized under the Healthy Forests Restoration Act of 2003. The intended effect of this action is to inform interested members of the public which newspapers will be used to publish legal notice of actions subject to the pre-decisional administrative review process at 36 CFR 218, thereby allowing them to receive constructive notice of the proposed actions, to provide clear evidence of timely notice, and to achieve consistency in administering the pre-decisional review process.
Publication of legal notices in the listed newspapers begins on March 1, 2016. This list of newspapers will remain in effect until it is superceded by a new list, published in the
Robin Dale, Alaska Region Group Leader for Appeals, Litigation, FOIA & Records; Forest Service, Alaska Region; P.O. Box 21628; Juneau, Alaska 99802-1628.
Robin Dale; Alaska Region Group Leader for Administrative Reviews, Litigation, FOIA & Records; (907) 586-9344.
This notice provides the list of newspapers that Responsible Officials in the Alaska Region will use to give notice of projects and activities implementing land and resource management plans, including hazardous fuel reduction projects authorized under the Healthy Forests Restoration Act of 2003, subject to the pre-decisional administrative review process at 36 CFR 218. The timeframe for objection to a proposed project subject to this process shall be based on the date of publication of the legal notice of the project in the newspaper of record identified in this notice. The newspapers to be used for giving notice of Forest Service projects in the Alaska Region are as follows:
Decisions of the Alaska Regional Forester: Juneau Empire, published daily except Saturday and official holidays in Juneau, Alaska; and the Alaska Dispatch News, published daily in Anchorage, Alaska.
Decisions of the Forest Supervisor and the Glacier and Seward District Rangers: Alaska Dispatch News, published daily in Anchorage, Alaska.
Decisions of the Cordova District Ranger: Cordova Times, published weekly in Cordova, Alaska.
Decisions of the Forest Supervisor and the Craig, Ketchikan/Misty, and Thorne Bay District Rangers: Ketchikan Daily News, published daily except Sundays and official holidays in Ketchikan, Alaska.
Decisions of the Admiralty Island National Monument Ranger, the Juneau District Ranger, the Hoonah District Ranger, and the Yakutat District Ranger: Juneau Empire, published daily except Saturday and official holidays in Juneau, Alaska.
Decisions of the Petersburg District Ranger: Petersburg Pilot, published weekly in Petersburg, Alaska.
Decisions of the Sitka District Ranger: Daily Sitlca Sentinel, published daily except Saturday, Sunday, and official holidays in Sitka, Alaska.
Decisions of the Wrangell District Ranger: Wrangell Sentinel, published weekly in Wrangell, Alaska.
Supplemental notices may be published in any newspaper, but the time frames for filing objections will be calculated based upon the date that legal notices are published in the newspapers of record listed in this notice.
Forest Service, USDA.
Notice of meeting.
The Idaho Panhandle Resource Advisory Committee (RAC) will meet in Coeur d'Alene, Idaho. The committee is authorized under the Secure Rural Schools and Community Self-Determination Act (the Act) and operates in compliance with the Federal Advisory Committee Act. The purpose of the committee is to improve collaborative relationships and to provide advice and recommendations to the Forest Service concerning projects and funding consistent with Title II of the Act. Additional RAC information, including the meeting agenda and the meeting summary/minutes can be found at the following Web site:
The meeting will be held March 11, 2016 at 9:00 a.m.
All RAC meetings are subject to cancellation. For status of meeting prior to attendance, please contact the person listed under
The meeting will be held at the Idaho Panhandle National Forests Supervisor's Office located at 3815 Schreiber Way, Coeur d'Alene, Idaho 83815.
Written comments may be submitted as described under
Shoshana Cooper, RAC Coordinator, by phone at 208-765-7211 or via email at
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339
The purpose of the meeting is:
1. Proposal review and recommendations.
The meeting is open to the public. The agenda will include time for people to make oral statements of three minutes or less. Individuals wishing to make an oral statement should request in writing by February 29, 2016 to be scheduled on the agenda. Anyone who would like to bring related matters to the attention of the committee may file written statements with the committee staff before or after the meeting. Written comments and requests for time for oral comments must be sent to Shoshana Cooper, RAC Coordinator, 3815 Schreiber Way, Coeur d'Alene, Idaho, 83815; or by email to
Rural Utilities Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35, as amended), the United States Department of Agriculture (USDA) Rural Development administers rural utilities programs through the Rural Utilities Service (RUS). RUS invites comments on the following information collection for which the Agency intends to request approval from the Office of Management and Budget (OMB).
Comments on this notice must be received by April 8, 2016.
Thomas P. Dickson, Acting Director, Program Development and Regulatory Analysis, USDA Rural Utilities Service, 1400 Independence Avenue SW., STOP 1522, Room 5164, South Building, Washington, DC 20250-1522. Telephone: (202) 690-4492. FAX: (202) 720-8435. Email:
The Office of Management and Budget's (OMB) regulation (5 CFR 1320) implementing provisions of the Paperwork Reduction Act of 1995 (Pub. L. 104-13) requires that interested members of the public and affected agencies have an opportunity to comment on information collection and recordkeeping activities (see 5 CFR 1320.8(d)). This notice identifies an information collection that RUS is submitting to OMB for extension.
Copies of this information collection can be obtained from Rebecca Hunt, Program Development and Regulatory Analysis, at (202) 205-3660, FAX (202) 720-8435 or email:
All responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public records.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (“Department”) is conducting an administrative review of the antidumping duty order on pure magnesium from the People's Republic of China (“PRC”). The period of review (“POR”) is May 1, 2014, through April 30, 2015. This review covers Tianjin Magnesium International, Co., Ltd. (“TMI”) and Tianjin Magnesium Metal Co., Ltd. (“TMM”) (collectively “TMI/
Shanah Lee, AD/CVD Operations, Office III, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-6386.
Merchandise covered by the order is pure magnesium regardless of chemistry, form or size, unless expressly excluded from the scope of the order. Pure magnesium is a metal or alloy containing by weight primarily the element magnesium and produced by decomposing raw materials into magnesium metal. Pure primary magnesium is used primarily as a chemical in the aluminum alloying, desulfurization, and chemical reduction industries. In addition, pure magnesium is used as an input in producing magnesium alloy. Pure magnesium encompasses products (including, but not limited to, butt ends, stubs, crowns and crystals) with the following primary magnesium contents:
(1) Products that contain at least 99.95% primary magnesium, by weight (generally referred to as “ultra pure” magnesium);
(2) Products that contain less than 99.95% but not less than 99.8% primary magnesium, by weight (generally referred to as “pure” magnesium); and
(3) Products that contain 50% or greater, but less than 99.8% primary magnesium, by weight, and that do not conform to ASTM specifications for alloy magnesium (generally referred to as “off-specification pure” magnesium).
“Off-specification pure” magnesium is pure primary magnesium containing magnesium scrap, secondary magnesium, oxidized magnesium or impurities (whether or not intentionally added) that cause the primary magnesium content to fall below 99.8% by weight. It generally does not contain, individually or in combination, 1.5% or more, by weight, of the following alloying elements: aluminum, manganese, zinc, silicon, thorium, zirconium and rare earths.
Excluded from the scope of the order are alloy primary magnesium (that meets specifications for alloy magnesium), primary magnesium anodes, granular primary magnesium (including turnings, chips and powder) having a maximum physical dimension (
Pure magnesium products covered by the order are currently classifiable under Harmonized Tariff Schedule of the United States (“HTSUS”) subheadings 8104.11.00, 8104.19.00, 8104.20.00, 8104.30.00, 8104.90.00, 3824.90.11, 3824.90.19 and 9817.00.90. Although the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope is dispositive.
On May 1, 2015, the Department published a notice of opportunity to request an administrative review of the antidumping duty order on pure magnesium from the PRC for the period May 1, 2014 through April 30, 2015.
On January 21, 2016, the Department placed on the record information obtained in response to a query to U.S. Customs and Border Protection (“CBP”) concerning imports into the United States of subject merchandise during the POR.
As explained in the memorandum from the Acting Assistant Secretary for Enforcement & Compliance, the Department has exercised its discretion to toll all administrative deadlines due to the recent closure of the Federal Government. All deadlines in this segment of the proceeding have been extended by four business days. The revised deadline for the preliminary results of this review is now February 5, 2016.
As noted in the “Background” section above, TMI and TMM each submitted timely-filed certifications indicating that it had no shipments of subject merchandise to the United States during the POR. The Department's review of CBP data supports this certification;
Therefore, based on TMI and TMM's certification and analysis information of the record, the Department preliminarily determines that TMI/TMM did not have any reviewable entries during the POR. In addition, the Department finds that consistent with its assessment practice in non-market economy (“NME”) cases, it is appropriate not to rescind the review in part in this circumstance but, rather, to complete the review with respect to TMI/TMM and to issue appropriate instructions to CBP based on the final results of the review.
Interested parties are invited to comment on the preliminary results and may submit case briefs and/or written comments within 30 days of the date of publication of this notice, pursuant to 19 CFR 351.309(c)(1)(ii). Rebuttal briefs, limited to issues raised in the case briefs, will be due five days after the due date for case briefs, pursuant to 19 CFR 351.309(d). Parties who submit case or rebuttal briefs in this proceeding are requested to submit with each argument a statement of the issue, a summary of the argument not to exceed five pages, and a table of statutes, regulations, and cases cited, in accordance with 19 CFR 351.309(c)(2) and (d)(2).
Pursuant to 19 CFR 351.310(c), interested parties who wish to request a hearing must submit a written request to the Assistant Secretary for Enforcement and Compliance, U.S. Department of Commerce. All documents must be filed electronically using Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (“ACCESS”). ACCESS is available to registered users at
Upon issuance of the final results, the Department will determine, and CBP shall assess, antidumping duties on all appropriate entries covered by this review. The Department intends to issue assessment instructions to CBP 15 days after the publication date of the final results of this review. Additionally, pursuant to a recently announced refinement to its assessment practice in NME cases, if the Department continues to determine that an exporter under review had no shipments of the subject merchandise, any suspended entries that entered under that exporter's case number (
The following cash deposit requirements will be effective upon publication of the final results of this administrative review for all shipments of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the publication date, as provided for by section 751(a)(2)(C) of the Act: (1) For TMI/TMM, which claimed no shipments, the cash deposit rate will remain unchanged from the rate assigned to TMI/TMM in the most recently completed review of the company; (2) for previously investigated or reviewed PRC and non-PRC exporters who are not under review in this segment of the proceeding but who have separate rates, the cash deposit rate will continue to be the exporter-specific rate published for the most recent period; (3) for all PRC exporters of subject merchandise that have not been found to be entitled to a separate rate, the cash deposit rate will be the PRC-wide rate of 141.49 percent; and (4) for all non-PRC exporters of subject merchandise which have not received their own rate, the cash deposit rate will be the rate applicable to the PRC exporter(s) that supplied that non-PRC exporter. These deposit requirements, when imposed, shall remain in effect until further notice.
This notice also serves as a preliminary reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement off antidumping duties prior to liquidation of the relevant entries during this period. Failure to comply with this requirement could result in the Secretary's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
This administrative review and notice are in accordance with sections 751(a)(1) and 777(i) of the Act and 19 CFR 351.213.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) is initiating an expedited review of the countervailing duty order on supercalendered paper from Canada with respect to Catalyst Pulp and Paper Sales Inc., Catalyst Paper Corporation, and Catalyst Paper (USA) (collectively, Catalyst) and Irving Paper Limited (Irving).
Effective date: February 8, 2016.
Dana Mermelstein or Toby Vandall, AD/CVD Operations, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone (202) 482-1391 and (202) 482-1664, respectively.
On December 10, 2015, the Department published the countervailing duty order on supercalendered paper from Canada.
In accordance with 19 CFR 351.214(k)(1)(i)-(iii), Catalyst and Irving each certified that they exported the subject merchandise to the United States during the period of investigation; that they were not affiliated with an exporter or producer that the Department individually examined in the investigation; and that they informed the Government of Canada, as the government of the exporting country, that the government will be required to provide a full response to the Department's questionnaire.
Therefore, in accordance with 19 CFR 351.214(k), we are initiating an expedited review of the countervailing duty order on supercalendered paper from Canada. Pursuant to 19 CFR 351.214(i)(1) and (k)(3), we intend to issue the preliminary results of this expedited review not later than 180 days from the date of initiation of this review.
Pursuant to 19 CFR 351.214(k)(3)(iii), the final results of this expedited review will not be the basis for the assessment of countervailing duties. Instead, this expedited review is intended to establish individual cash deposit rates for Catalyst and Irving, or to exclude from the countervailing duty order a company for which the final results of review are zero or
Interested parties must submit applications for disclosure under administrative protective orders in accordance with 19 CFR 351.305 and 351.306.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of SEDAR 46 Review Workshop for U.S. Caribbean Data-Limited Species.
The SEDAR 46 assessment of the U.S. Caribbean Data-Limited Species will consist of: A Data/Assessment Workshop; a series of Assessment webinars; and a Review Workshop.
The SEDAR 46 Review Workshop will be held from 9 a.m. on February 23, 2016 until 6 p.m. on February 25, 2016. See
Julie Neer, SEDAR Coordinator; telephone: (843) 571-4366 or toll free (866) SAFMC-10; fax: (843) 769-4520; email:
The Gulf of Mexico, South Atlantic, and Caribbean Fishery Management Councils, in conjunction with NOAA Fisheries and the Atlantic and Gulf States Marine Fisheries Commissions have implemented the Southeast Data, Assessment and Review (SEDAR) process, a multi-step method for determining the status of fish stocks in the Southeast Region. SEDAR is a three step process including: (1) Data Workshop; (2) Assessment Process utilizing webinars; and (3) Review Workshop. The product of the Data Workshop is a data report which compiles and evaluates potential datasets and recommends which datasets are appropriate for assessment analyses. The product of the Assessment Process is a stock assessment report which describes the fisheries, evaluates the status of the stock, estimates biological benchmarks, projects future population conditions, and recommends research and monitoring needs. The assessment is independently peer reviewed at the Review Workshop. The product of the Review Workshop is a Summary documenting panel opinions regarding the strengths and weaknesses of the stock assessment and input data. Participants for SEDAR Workshops are appointed by the Gulf of Mexico, South Atlantic, and Caribbean Fishery Management Councils and NOAA Fisheries Southeast Regional Office, HMS Management Division, and Southeast Fisheries Science Center. Participants include: Data collectors and database managers; stock assessment scientists, biologists, and researchers; constituency representatives including fishermen, environmentalists, and non-governmental organizations (NGOs); international experts; and staff of Councils, Commissions, and state and federal agencies.
The items of discussion in the Review Workshop agenda are as follows:
The Review Panel participants will review the stock assessment reports to determine if they are scientifically sound.
Although non-emergency issues not contained in this agenda may come before this group for discussion, those issues may not be the subject of formal action during this meeting. Action will be restricted to those issues specifically identified in this notice and any issues arising after publication of this notice that require emergency action under section 305(c) of the Magnuson-Stevens Fishery Conservation and Management Act, provided the public has been notified of the intent to take final action to address the emergency.
This meeting is physically accessible to people with disabilities. Requests for auxiliary aids should be directed to the Council office (see
The times and sequence specified in this agenda are subject to change.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; public meeting.
The Mid-Atlantic Fishery Management Council will hold a public meeting of the Scientific Uncertainty Subcommittee of the Scientific and Statistical Committee.
The meeting will be held on Tuesday, February 23, 2016, beginning at 10 a.m. and conclude by 4 p.m. For agenda details, see
The meeting will at the DoubleTree by Hilton Baltimore-BWI Airport; 890 Elkridge Landing Rd, Linthicum Heights, MD 21090.
Christopher M. Moore, Ph.D., Executive Director, Mid-Atlantic Fishery Management Council, telephone: (302) 526-5255.
The purpose of the meeting is to conduct a peer review of recent analyses conducted by the Northeast Regional Stock Assessment Southern Demersal Working Group (SDWG) relative to stock delineation in the population dynamics models being developed for the northern stock (Cape Hatteras, North Carolina to Maine) of black sea bass (Centropristis striata). The results of this review will help guide the SDWG in the treatment of issues related to specification of spatial stock structure in the operating model for this species.
This meeting is physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aid should be directed to M. Jan Saunders, (302) 526-5251, at least 5 days prior to the meeting date.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; receipt of application for permit amendment.
Notice is hereby given that the Alaska Department of Fish and Game (ADF&G), Division of Wildlife Conservation, Juneau, AK [Responsible Party: Robert Small, Ph.D.], has applied for an amendment to Scientific Research Permit No. 18537.
Written, telefaxed, or email comments must be received on or before March 9, 2016.
The application and related documents are available for review by selecting “Records Open for Public Comment” from the “Features” box on the Applications and Permits for Protected Species home page,
These documents are also available upon written request or by appointment in the Permits and Conservation Division, Office of Protected Resources, NMFS, 1315 East-West Highway, Room 13705, Silver Spring, MD 20910; phone (301) 427-8401; fax (301) 713-0376.
Written comments on this application should be submitted to the Chief, Permits and Conservation Division, at the address listed above. Comments may also be submitted by facsimile to (301) 713-0376, or by email to
Those individuals requesting a public hearing should submit a written request to the Chief, Permits and Conservation Division at the address listed above. The request should set forth the specific reasons why a hearing on this application would be appropriate.
Rosa L. González or Amy Sloan, (301) 427-8401.
The subject amendment to Permit No. 18537 is requested under the authority of the Marine Mammal Protection Act of 1972, as amended (16 U.S.C. 1361
Permit No. 18537, issued on August 8, 2014 (79 FR 19578), authorizes takes of Steller sea lions during aerial, vessel, and ground surveys in support of the long-term Steller sea lions research program. It also authorizes incidental disturbance of California sea lions (
The permit holder is requesting the permit be amended to increase the number of California and Steller (wDPS) sea lions taken during aerial surveys from 4,725 to 10,000, and from 48,000 to 75,000, respectively. The request is in response to observed trends within recent years of increasing northerly movement of California sea lions, and as a result of this, an increase in observed animals in the current research area. In addition, the use of more sophisticated equipment has provided better resolution and quality of images taken, and, therefore, higher differentiation among pinnipeds observed. The permit holder also requests authorization to increase the volume on a single blood draw from Steller sea lions from up to 1 ml/kg to up to 4 ml/kg. The increase would support research projects related to the impacts of contaminants on immune and endocrine parameters in young Steller sea lions.
In compliance with the National Environmental Policy Act of 1969 (42 U.S.C. 4321
Concurrent with the publication of this notice in the
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; issuance of permit amendments.
Notice is hereby given that two major permit amendments have been issued: Permit No. 16193-01 has been issued to Todd Robeck, D.V.M, Ph.D., Sea World Parks and Entertainment Corp, 500 Sea World Drive, San Diego, CA 92109; and, Permit No. 17157-02 has been issued to Stephen John Trumble, Ph.D., Baylor University, 101 Bagby Ave., Waco, TX 76706.
The permit amendments and related documents are available for review upon written request or by appointment in the Permits and Conservation Division, Office of Protected Resources, NMFS, 1315 East-West Highway, Room 13705, Silver Spring, MD 20910; phone (301) 427-8401; fax (301) 713-0376.
Jennifer Skidmore or Amy Sloan, (301) 427-8401.
On December 8, 2015, notices were published in the
Permit No. 16193, issued on August 28, 2012, authorizes the permit holder to receive, import, and export cetacean and pinniped specimens to study reproductive physiology, including endocrinology, gamete biology, and cryophysiology. Permit No. 16193-01 amends the authorization to include unlimited samples from up to 300 wild Amazon River dolphins (
Permit No. 17157, issued on July 18, 2012, and amended on November 7, 2014, authorizes the receipt, import and export of up to 25 earplugs annually of each of the following species of whale: blue (
Permit No. 17157-02 authorizes an increase in the number of animals that samples that may be received, imported, and exported from 25 to 100 individuals annually. In addition, the permit has been amended to authorize the receipt, import, and export of baleen samples from blue and fin whales.
In compliance with the National Environmental Policy Act of 1969 (42 U.S.C. 4321
As required by the ESA, issuance of this permit was based on a finding that such permit: (1) Was applied for in good faith; (2) will not operate to the disadvantage of such endangered species; and (3) is consistent with the purposes and policies set forth in section 2 of the ESA.
Commodity Futures Trading Commission.
Notice of meeting.
The Commodity Futures Trading Commission (CFTC or Commission) announces that on Tuesday, February 23, 2016, from 9:45 a.m. to 3:45 p.m., the CFTC's Technology Advisory Committee (TAC) will hold a rescheduled public meeting at the CFTC's Washington, DC headquarters. The TAC meeting previously scheduled for January 26, 2016, from 9:45 a.m. to 3:45 p.m., was canceled due to inclement weather that closed the Federal Government. The TAC will discuss: (1) The Commission's proposed Regulation Automated Trading (Reg AT); (2) swap data standardization and harmonization; and (3) blockchain and the potential application of distributed ledger technology to the derivatives market.
The meeting will be held on Tuesday, February 23, 2016 from 9:45 a.m. to 3:45 p.m. Members of the public who wish to submit written statements in connection with the meeting should submit them by Monday, February 22, 2016.
The meeting will take place in the Conference Center at the CFTC's headquarters, Three Lafayette Centre, 1155 21st Street NW., Washington, DC 20581. Written statements should be submitted by mail to: Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st Street NW., Washington, DC 20581, attention: Office of the Secretary, or by electronic mail to:
Ward P. Griffin, TAC Designated Federal Officer, Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st Street NW., Washington, DC 20581, (202) 418-5425.
The meeting will be open to the public with seating on a first-come, first-served basis. Members of the public may also listen to the meeting by telephone by calling a domestic toll-free telephone or international toll or toll-free number to
5 U.S.C. app. 2 § 10(a)(2).
U.S. Consumer Product Safety Commission.
Notice of availability.
The Consumer Product Safety Commission (“CPSC”) has drafted a Strategic Plan for 2016-2020. CPSC seeks comments from the public on the draft plan.
Submit comments by March 9, 2016.
You may submit comments, identified by Docket No. CPSC-2016-0002, by any of the following methods:
Anne Inserra, Office of Financial Management, Planning and Evaluation, U.S. Consumer Product Safety Commission, 4330 East-West Highway, Bethesda, MD 20814; telephone: (301) 504-7421; email:
The CPSC is an independent federal regulatory agency with a public health and safety mission to protect the public from the unreasonable risks of injury and death from consumer products. The CPSC is providing notice that the agency is seeking public comments on its new draft 2016-2020 Strategic Plan.
Under the draft new Strategic Plan, the CPSC's mission is “Keeping Consumers Safe.” The agency's overarching vision is “A nation free from unreasonable risks of injury and death from consumer products.” The CPSC will work to achieve four strategic goals that will contribute to realizing the agency's vision and achieving its mission. CPSC's programs will align with the strategic goals, and staff will implement strategies to achieve the strategic goals. The strategic goals are:
1. Cultivate the most effective consumer product safety workforce.
2. Prevent hazardous products from reaching consumers.
3. Respond quickly to address hazardous consumer products in the marketplace and with consumers.
4. Communicate useful information quickly and effectively to better inform decisions.
The draft 2016-2020 Strategic Plan sets out how the CPSC will pursue the four strategic goals. The draft Strategic Plan is available on the Commission's Web site at:
The CPSC seeks comments on all aspects of the draft 2016-2020 Strategic Plan. CPSC has a wide range of external stakeholders from industry, trade associations, consumer groups, nonprofits, and standards development organizations, as well as from the international, congressional, federal, state, and local sectors. The agency looks forward to receiving comments from all individuals and entities involved in, and affected by, the CPSC's activities. Please provide comments as directed in the
Environmental Protection Agency (EPA).
Notice.
This document announces the Office of Management and Budget (OMB) responses to Agency Clearance requests, in compliance with the Paperwork Reduction Act (44 U.S.C. 3501
Courtney Kerwin (202) 566-1669, or email at
EPA ICR Number 1723.07; Importation of Nonroad Engines and Recreational Vehicles (Renewal); 40 CFR 85, 40 CFR part 89, 40 CFR part 90, 40 CR part 91, 40 CFR part 92, 40 CFR part 94, and 40 CFR part 1068; was approved without change on 5/20/2015; OMB Number 2060-0320; expires on 5/31/2016.
EPA ICR Number 0222.10; EPA's Light-Duty In-Use Vehicle Testing Program (Renewal); was approved with change on 5/14/2015; OMB Number 2060-0086; expires on 5/31/2018.
EPA ICR Number 1907.09; Recordkeeping and Reporting Requirements Regarding the Sulfur Content of Motor Vehicle Gasoline under the Tier 2 Rule (Final Rule for Tier 3) (Revision); 40 CFR 80, subpart O, 40 CFR 80.210, 40 CFR 80.270, 40 CFR 80.330, 40 CFR 80.340, 40 CFR 80.370, 40 CFR 80.380, 40 CFR 80.400, and 40 CFR 80.415; was approved without change on 5/13/2015; OMB Number 2060-0437; expires on 5/31/2018.
EPA ICR Number 2489.01; Willingness to Pay Survey for Salmon Recovery in the Willamette Watershed (New); was approved with change on 5/8/2015; OMB Number 2080-0081; expires on 5/31/2018.
EPA ICR Number 2410.03; NESHAP for Group I Polymers and Resins (Renewal); 40 CFR 63, subparts A and U; was approved without change on 5/7/2015; OMB Number 2060-0665; expires on 5/31/2018.
EPA ICR Number 1693.08; Plant-Incorporated Protectants; CBI Substantiation and Adverse Effects Reporting (Renewal); 40 CFR 174.71 and 40 CFR part 174.9; was approved without change on 5/6/2015; OMB Number 2070-0142; expires on 5/31/2018.
EPA ICR Number 1781.07; NESHAP for Pharmaceutical Production (Renewal); 40 CFR 63, subparts A and GGG; was approved without change on 5/6/2015; OMB Number 2060-0358; expires on 5/31/2018.
EPA ICR Number 1807.07; NESHAP for Pesticide Active Ingredient Production (Revision); 40 CFR 63, subpart A and 40 CFR 63, subpart MMM; was approved without change on 5/6/2015; OMB Number 2060-0370; expires on 6/30/2015.
EPA ICR Number 2031.07; Protection of Stratospheric Ozone: Request for Applications from Critical use Exemption for the Phase-out of Methyl Bromide (Change); 40 CFR 82; was approved without change on 5/5/2015; OMB Number 2060-0482; expires on 5/31/2018.
EPA ICR Number 1131.11; NSPS for Glass Manufacturing Plants (Renewal); 40 CFR 60 Subpart A and 40 CFR 60 Subpart CC; was approved with change on 5/4/2015; OMB Number 2060-0054; expires on 5/31/2018.
EPA ICR Number 1125.07; NESHAP for Beryllium Rocket Motor Fuel Firing (Renewal); 40 CFR 61, subparts A and D; was approved with change on 5/4/2015; OMB Number 2060-0394; expires on 5/31/2018.
EPA ICR Number 2502.01; TSCA Sections 402 and Section 404 Training, Certification, Accreditation and Standards for Lead-Based Paint Activities and Renovation, Repair and Painting (Proposed Rule); 40 CFR 745.225; OMB filed comment on 5/6/2015.
Environmental Protection Agency (EPA).
Notice.
EPA is announcing its receipt of test data submitted pursuant to a test rule issued by EPA under the Toxic Substances Control Act (TSCA). As required by TSCA, this document identifies each chemical substance and/or mixture for which test data have been received; the uses or intended uses of such chemical substance and/or mixture; and describes the nature of the test data received. Each chemical substance and/or mixture related to this announcement is identified in Unit I. under
Information about the following chemical substances and/or mixtures is provided in Unit IV.:
Section 4(d) of TSCA (15 U.S.C. 2603(d)) requires EPA to publish a notice in the
A docket, identified by the docket identification (ID) number EPA-HQ-OPPT-2013-0677, has been established for this
The docket for this
This unit contains the information required by TSCA section 4(d) for the test data received by EPA.
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2.
3.
15 U.S.C. 2601
Federal Communications Commission.
Notice and request for comments.
As part of its continuing effort to reduce paperwork burdens, and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3520), the Federal Communication Commission (FCC or Commission) invites the general public and other Federal agencies to take this opportunity to comment on the following information collections. Comments are requested concerning: Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; the accuracy of the Commission's burden estimate; ways to enhance the quality, utility, and clarity of the information collected; ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and ways to further reduce the information collection burden on small business concerns with fewer than 25 employees.
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the PRA that does not display a valid OMB control number.
Written comments should be submitted on or before March 9, 2016. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contacts below as soon as possible.
Direct all PRA comments to Nicholas A. Fraser, OMB, via email
For additional information or copies of the information collection, contact Cathy Williams at (202) 418-2918. To view a copy of this information collection request (ICR) submitted to OMB: (1) Go to the Web page
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, February 23, 2016, from 9:00 a.m. to 3:30 p.m. (EST).
Federal Communications Commission, 445 12th Street SW., Washington, DC 20554, in the Commission Meeting Room.
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
At its February 23, 2016 meeting, the Committee is expected to receive and consider a report on the activities of its Communications Subcommittee; a report and recommendation from its Emergency Communications Subcommittee regarding the provision of N-1-1 services through telecommunications relay services; an update from its Emergency Subcommittee regarding improvements to Wireless Emergency Alerts (WEAs) proposed by the FCC in November 2015; a recommendation from its Relay & Equipment Distribution Subcommittee regarding the compatibility of the Commission's Accessible Communication for Everyone (“ACE”) platform with Next-Generation 911 services; a recommendation from its Technology Transitions Subcommittee regarding ways to address the transition to real-time text; and recommendations from its Video Programming Subcommittee regarding (1) interagency collaboration to address access to captioning and video description in places of public accommodations and other venues, such as aircraft, where video programming may be shown; and (2) questions for the Commission to consider in a rulemaking that may address the number of television programming hours that must be video described. The Committee will also (1) receive a report on the communication needs of deaf people with mobility disabilities from Mark Hill, President of the Cerebral Palsy and Deaf Organization; (2) hear presentations from Commission staff on recent activities; and (3) discuss new issues for its consideration.
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
To request materials in accessible formats for people with disabilities (Braille, large print, electronic files, audio format), send an email to
Federal Communications Commission.
Notice and request for comments.
As part of its continuing effort to reduce paperwork burdens, and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3520), the Federal Communications Commission (FCC or Commission) invites the general public and other Federal agencies to take this opportunity to comment on the following information collections. Comments are requested concerning: whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; the accuracy of the Commission's burden estimate; ways to enhance the quality, utility, and clarity of the information collected; ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and ways to further reduce the information collection burden on small business concerns with fewer than 25 employees.
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the PRA that does not display a valid OMB control number.
Written PRA comments should be submitted on or before April 8, 2016. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
Direct all PRA comments to Cathy Williams, FCC, via email
For additional information about the information collection, contact Cathy Williams at (202) 418-2918.
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 March 4, 2016.
A. Federal Reserve Bank of Chicago (Colette A. Fried, Assistant Vice President) 230 South LaSalle Street, Chicago, Illinois 60690-1414:
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The companies listed in this notice have given notice under section 4 of the Bank Holding Company Act (12 U.S.C. 1843) (BHC Act) and Regulation Y, (12 CFR part 225) to engage
Each notice is available for inspection at the Federal Reserve Bank indicated. The notice also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the question whether the proposal complies with the standards of section 4 of the BHC Act.
Unless otherwise noted, comments regarding the applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than February 23, 2016.
A. Federal Reserve Bank of Chicago (Colette A. Fried, Assistant Vice President) 230 South LaSalle Street, Chicago, Illinois 60690-1414:
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 February 23, 2016.
A. Federal Reserve Bank of Atlanta (Chapelle Davis, Assistant Vice President) 1000 Peachtree Street NE., Atlanta, Georgia 30309. Comments can also be sent electronically to
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Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for public comments regarding an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act, the Regulatory Secretariat Division will be submitting to the Office of Management and Budget (OMB) a request to review and approve an extension of a previously approved information collection requirement concerning Taxpayer Identification Number Information.
Submit comments on or before April 8, 2016.
Submit comments identified by Information Collection 9000-0097, Taxpayer Identification Number Information, by any of the following methods:
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Submit comments via the Federal eRulemaking portal by searching the OMB control number. Select the link “Submit a Comment” that corresponds with “Information Collection 9000-0097, Taxpayer Identification Number Information”. Follow the instructions provided at the “Submit a Comment” screen. Please include your name, company name (if any), and “Information Collection 9000-0097, Taxpayer Identification Number Information” on your attached document.
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Mr. Curtis E. Glover, Sr., Procurement Analyst, Contract Policy Division, GSA, 202-501-1448 or email at
In accordance with 31 U.S.C. 7701(c), a contractor doing business with a Government agency is required to furnish its Tax Identification Number (TIN) to that agency. Also, 31 U.S.C. 3325(d) requires the Government to include, with each certified voucher prepared by the Government payment office and submitted to a disbursing official, the TIN of the contractor receiving payment under the voucher. 26 U.S.C. 6050M, as implemented in the Department of Treasury, Internal Revenue Service (IRS) regulations at Title 26 of the Code of Federal Regulations (CFR), requires heads of Federal executive agencies to report certain information to the IRS. 26 U.S.C. 6041 and 6041A, as implemented in 26 CFR, in part, requires payors, including Government agencies, to report to the IRS, on form 1099, payments made to certain contractors.
To comply with the requirements of 31 U.S.C. 7701(c) and 3325(d), reporting requirements of 26 U.S.C. 6041, 6041A, and 6050M, and implementing regulations issued by the IRS in 26 CFR, FAR clause 52.204-3, Taxpayer Identification, requires a potential Government contractor to submit, among other information, its TIN. The TIN may be used by the Government to collect and report on any delinquent amounts arising out of the contractor's relationship with the Government. A contractor is not required to provide its TIN on each contract in accordance with FAR clause 52.204-3, Taxpayer Identification, when FAR clause 52.204-7, Central Contractor Registration, is inserted in contracts. FAR clause 52.204-7 requires a potential Federal contractor to provide its TIN in the Central Contractor Registration (CCR) system.
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the Federal Acquisition Regulation (FAR), and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for public comments regarding an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act, the Regulatory Secretariat Division will be submitting to the Office of Management and Budget (OMB) a request to review and approve an extension of a previously approved information collection requirement concerning the Central Contractor Registration database.
Submit comments on or before April 8, 2016.
Submit comments identified by Information Collection 9000-0159, Central Contractor Registration, by any of the following methods:
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Mr. Curtis E. Glover, Sr., Procurement Analyst, Office of Governmentwide Policy, GSA, 202-501-1448, or via email at
The Federal Acquisition Regulation (FAR) Subpart 4.11 prescribes policies and procedures for requiring contractor registration in the Central Contractor Registration (CCR) database. The CCR is the primary vendor database for the U.S. Federal Government. CCR collects, validates, stores, and disseminates data in support of agency acquisition missions.
Both current and potential Federal Government vendors are required to register in CCR in order to be awarded contracts by the Federal Government. Vendors are required to complete a one-time registration to provide basic information relevant to procurement and financial transactions. Vendors must update or renew their registration at least once per year to maintain an active status.
The CCR validates the vendor information and electronically share the secure and encrypted data with Federal agency finance offices to facilitate paperless payments through electronic funds transfer. Additionally, CCR shares the data with Federal Government procurement and electronic business systems.
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the Federal Acquisition Regulation (FAR), and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Obtaining Copies of Proposals: Requesters may obtain a copy of the information collection documents from the General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405, telephone 202-501-4755. Please cite OMB Control Number 9000-0159, Central Contractor Registration, in all correspondence.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for public comments regarding a new OMB information clearance.
Under the provisions of the Paperwork Reduction Act of 1995, the Regulatory Secretariat Division will be submitting to the Office of Management and Budget (OMB) a request to review and approve a new information collection requirement regarding Use of Project Labor Agreements for Federal Construction Projects.
Submit comments on or before April 8, 2016.
Submit comments identified by Information Collection 9000-0175, Use of Project Labor Agreements for Federal Construction Projects, by any of the following methods:
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Submit comments via the Federal eRulemaking portal by searching the OMB control number. Select the link “Submit a Comment” that corresponds with “Information Collection 9000-0175, Use of Project Labor Agreements for Federal Construction Projects”. Follow the instructions provided at the “Submit a Comment” screen. Please include your name, company name (if any), and “Information Collection 9000-0175, Use of Project Labor Agreements for Federal Construction Projects” on your attached document.
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Mr. Edward Loeb, Procurement Analyst, Office of Governmentwide Acquisition Policy, at telephone 202-501-0650 or via email to
FAR 22.501 prescribes policies and procedures to implement Executive Order 13502, February 6, 2009 which encourages Federal agencies to consider the use of a project labor agreement (PLA), as they may decide appropriate, on large-scale construction projects, where the total cost to the Government is more than $25 million, in order to promote economy and efficiency in Federal procurement. A PLA is a pre-hire collective bargaining agreement with one or more labor organizations that establishes the terms and conditions of employment for a specific construction project. FAR 22.503(b) provides that an agency may, if appropriate, require that every contractor and subcontractor engaged in construction on the project agree, for that project, to negotiate or become a party to a project labor agreement with one or more labor organizations if the agency decides that the use of project labor agreements will—
(1) Advance the Federal Government's interest in achieving economy and efficiency in Federal procurement,
(2) Be consistent with law.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for an extension of an information collection requirement regarding an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act, Regulatory Secretariat Division will be submitting to the Office of Management and Budget (OMB) a request to review and approve an extension of a previously approved information collection requirement concerning Accident Prevention Plans and Recordkeeping.
Submit comments on or before April 8, 2016.
Submit comments identified by Information Collection 9000-0060, Accident Prevention Plans and Recordkeeping by any of the following methods:
• Regulations.gov:
• Regulations.gov:
Submit comments via the Federal eRulemaking portal by searching for Information Collection 9000-0060, Accident Prevention Plans and Recordkeeping. Select the link “Comment Now” that corresponds with “Information Collection 9000-0060, Accident Prevention Plans and Recordkeeping”. Follow the instructions provided on the screen. Please include your name, company name (if any), and “Information Collection 9000-0060, Accident Prevention Plans and Recordkeeping” on your attached document.
• Mail: General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405. ATTN: Ms. Flowers/IC 9000-0060, Accident Prevention Plans and Recordkeeping.
Mr. Curtis E. Glover, Sr., Procurement Analyst, Contract Policy Division, GSA, telephone 202-501-1448 or email at
The FAR clause at 52.236-13, Accident Prevention, requires Federal construction contractors to keep records of accidents incident to work performed under the contract that result in death, traumatic injury, occupational disease or damage to property, materials, supplies or equipment. Records of personal inquiries are required by the Department of Labor's (DOL) Occupational Safety and Health Administration regulations (OSHA). The records maintained by the contractor are used to evaluate compliance and may be used in workmen's compensation cases. The Federal Acquisition Regulation (FAR) requires records of damage to property, materials, supplies or equipment to provide background information when claims are brought against the Government.
If the contract involves work of a long duration, or hazardous nature, the contracting officer shall insert the clause with its alternate that requires the contractor to submit a written proposed plan for implementing the clause. The plan shall include an analysis of the significant hazards to life, limb, and property inherent in performing the contract and a plan for controlling the hazards. The Accident Prevention Plan (APP) is analyzed by the contracting officer along with the agency safety representatives to determine if the proposed plan will meet the requirements of safety regulations and applicable statutes.
Public comments are particularly invited on: Whether this collection of information is necessary; whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Commission to Eliminate Child Abuse and Neglect Fatalities, General Services Administration.
Meetings notice.
The Commission to Eliminate Child Abuse and Neglect Fatalities (CECANF), a Federal Advisory Committee established by the Protect Our Kids Act of 2012, will hold conference calls open to the public on the following dates: Sunday, February 14, 2016, and Monday, February 15, 2016.
The meeting on Sunday, February 14, 2016, will be held from 12:00 p.m. to 4:00 p.m., Eastern Standard Time (EST). The meeting on Monday, February 15, 2016, will be held from 4:00 p.m. to 8:00 p.m., Eastern Standard Time (EST).
CECANF will convene these meetings via conference call. Submit comments, identified by “Notice-CECANF-2016-03,” by either of the following methods:
•
•
Visit the CECANF Web site at
However, members of the public wishing to comment should follow the steps detailed under the heading
The reason CECANF is providing less than 15 calendar days' notice for this meeting, is because of the short timeframe allowed for Commissioners to hold a final deliberation on the draft report before its publication date.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for public comments regarding an extension of a previously existing OMB clearance.
Under the provisions of the Paperwork Reduction Act, the Regulatory Secretariat Division will be submitting to the Office of Management and Budget (OMB) a request to review and approve an extension of a previously approved information collection requirement concerning permits, authorities, or franchises for regulated transportation. A notice was published in the
Submit comments on or before March 9, 2016.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: Office of Information and Regulatory Affairs of OMB, Attention: Desk Officer for GSA, Room 10236, NEOB, Washington, DC 20503. Additionally submit a copy to GSA by any of the following methods:
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Mr. Michael O. Jackson, Procurement Analyst, Office of Governmentwide Acquisition Policy, GSA 202-208-4949 or email
The FAR requires insertion of clause 52.247-2, Permits, Authorities, or Franchises, when regulated transportation is involved. The clause requires the contractor to indicate whether it has the proper authorization from the Federal Highway Administration (or other cognizant regulatory body) to move material. The contractor may be required to provide copies of the authorization before moving material under the contract. The clause also requires the contractor, at its expense, to obtain and maintain any permits, franchises, licenses, and other authorities issued by State and local governments. The Government may request to review the documents to ensure that the contractor has complied with all regulatory requirements.
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the Federal Acquisition Regulations (FAR), and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Please cite OMB Control No. 9000-0053, Permits, Authorities, or Franchises, in all correspondence.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for public comments regarding an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act, the Regulatory Secretariat Division will be submitting to the Office of Management and Budget (OMB) a request to review and approve an extension of a previously approved information collection requirement concerning “Information Collection 9000-0057, Evaluation of Export Offers.” A notice was published in the
Submit comments on or before March 9, 2016.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: Office of Information and Regulatory Affairs of OMB, Attention: Desk Officer for GSA, Room 10236, NEOB, Washington, DC 20503. Additionally submit a copy to GSA by any of the following methods:
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Mr. Curtis E. Glover, Sr., Procurement Analyst, Office of Governmentwide Acquisition Policy, GSA, 202-501-4082 or via email at
Offers submitted in response to Government solicitations must be evaluated and awards made on the basis of the lowest laid down cost to the Government at the overseas port of discharge, via methods and ports compatible with required delivery dates and conditions affecting transportation know at the time of evaluation. FAR provision 52.247-51, “Evaluation of Export Offers,” is required for insertion in Government solicitations when supplies are to be exported through Contiguous United States (CONUS) ports and offers are solicited on a free onboard (f.o.b.) origin or f.o.b. destination basis. The provision has three alternates, to be used (1) when the CONUS ports of export are DoD water terminals, (2) when offers are solicited on an f.o.b. origin only basis, and (3) when offers are solicited on an f.o.b. destination only basis. The provision
Public comments are particularly invited on: Whether this collection of information is necessary; whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).
Notice with comment period.
Under the National Childhood Vaccine Injury Act (NCVIA) (42 U.S.C. 300aa-26), the Centers for Disease Control and Prevention (CDC) within the Department of Health and Human Services (HHS) develops vaccine information materials that all health care providers are required to give to patients/parents prior to administration of specific vaccines. HHS/CDC seeks written comment on the proposed updated vaccine information statements for hepatitis A and hepatitis B vaccines.
Written comments must be received on or before April 8, 2016.
You may submit comments, identified by Docket No. CDC-2016-0015, by any of the following methods:
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Skip Wolfe (
The National Childhood Vaccine Injury Act of 1986 (Pub. L. 99-660), as amended by section 708 of Public Law 103-183, added section 2126 to the Public Health Service Act. Section 2126, codified at 42 U.S.C. 300aa-26, requires the Secretary of Health and Human Services to develop and disseminate vaccine information materials for distribution by all health care providers in the United States to any patient (or to the parent or legal representative in the case of a child) receiving vaccines covered under the National Vaccine Injury Compensation Program (VICP).
Development and revision of the vaccine information materials, also known as Vaccine Information Statements (VIS), have been delegated by the Secretary to the Centers for Disease Control and Prevention (CDC). Section 2126 requires that the materials be developed, or revised, after notice to the public, with a 60-day comment period, and in consultation with the Advisory Commission on Childhood Vaccines, appropriate health care provider and parent organizations, and the Food and Drug Administration. The law also requires that the information contained in the materials be based on available data and information, be presented in understandable terms, and include:
(1) A concise description of the benefits of the vaccine,
(2) A concise description of the risks associated with the vaccine,
(3) A statement of the availability of the National Vaccine Injury Compensation Program, and
(4) Such other relevant information as may be determined by the Secretary.
The vaccines initially covered under the National Vaccine Injury Compensation Program were diphtheria, tetanus, pertussis, measles, mumps, rubella and poliomyelitis vaccines. Since April 15, 1992, any health care provider in the United States who intends to administer one of these covered vaccines is required to provide copies of the relevant vaccine information materials prior to administration of any of these vaccines. Since then, the following vaccines have been added to the National Vaccine Injury Compensation Program, requiring use of vaccine information materials for them as well: Hepatitis B,
HHS/CDC is proposing updated versions of the hepatitis A and hepatitis B vaccine information statements.
The vaccine information materials referenced in this notice are being developed in consultation with the Advisory Commission on Childhood Vaccines, the Food and Drug Administration, and parent and health care provider groups.
We invite written comment on the proposed revised vaccine information materials entitled “Hepatitis A Vaccine: What You Need to Know” and “Hepatitis B Vaccine: What You Need to Know.” Copies of the proposed vaccine information materials are available at
NCEHS-CCP will support the effective implementation of new EHS-CCP grants by disseminating information through training and technical assistance (T/TA) and resources and materials. NCEHS-CCP is primarily targeted to T/TA providers working directly with the EHS-CCP grantees (including Office of Head Start (OHS) and Office of Child Care (OCC) National Centers, regional training and technical assistance (T/TA) specialists, and implementation planners and fiscal consultants). State and federal agencies (including OHS and OCC federal staff, Child Care and Development Fund (CCDF) administrators, Head Start state and national collaboration office directors), as well as EHS-CCP grantees will also find helpful information on partnerships through NCEHS-CCP's resources.
NCEHS-CCP at ZERO TO THREE is proposing to conduct a descriptive study of NCEHS-CCP that will provide information that will document the activities and progress of NCEHS-CCP toward its goals and objectives. Findings from the evaluation will be translated into action steps to inform continuous quality improvement of NCEHS-CCP.
The proposed data collection activities for the descriptive study of NCEHS-CCP will include the following components:
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A 60-Day
In compliance with the requirements of Section 506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Administration for Children and Families is soliciting public comment on the specific aspects of the information collection described above. Copies of the proposed collection of information can be obtained and comments may be forwarded by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 370 L'Enfant Promenade SW., Washington, DC 20447, Attn: ACF Reports Clearance Officer. Email address:
The Department specifically requests comments on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted within 60 days of this publication.
Independent Living Administration, Administration for Community Living, HHS.
Notice.
The Administration for Community Living (ACL) is announcing that the proposed collection of information listed below has been submitted to the Office of Management and Budget (OMB) for review and clearance. Under the Paperwork Reduction Act of 1995 (the PRA), Federal agencies are required to publish notice in the
Submit written comments on the collection of information by March 9, 2016.
Submit written comments on the collection of information by email to
Veronica Hogan, Administration for Community Living, Washington, DC 20201. Telephone: (202) 795-7365; email:
The State Plan for Independent Living (SPIL) Public Law (105-220) for the State Independent Living (SILS) and Centers for Independent Living (CIL) program authorized by title VII, chapter 1, of the Rehabilitation Act of 1973, as Amended by the Workforce Innovation and Opportunity Act (WIOA, Pub. L. 113-128) [Rehabilitation Act]. States are required to submit an approvable SPIL in order to receive federal funding under the State Independent Living Services (SILS) and Centers for Independent Living (CIL) programs authorized by title VII, chapter 1, of the
If the SPIL is not extended and the data collection not conducted, ACL will not be authorized to fund the IL programs and, as a result, the availability of independent living services in the states will be severely limited.
Under the PRA (44 U.S.C. 3501-3520), Federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes agency request or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal agencies to provide a 60-day notice in the
The Independent Living Program is required by federal statute and regulation requires the collection of this information every three years. The three-year period for the next SPIL is FY 2017-2019. The SPIL provided in writing to the Administration for Community Living, Administration on Disabilities, Independent Living Administration. The five core services are: Advocacy, information and referral, independent living skills training, peer counseling, and transition services. WIOA included three prongs to the 5th core service:
• Facilitating the transition of individuals with significant disabilities from nursing homes and other institutions to home and community-based residences, with the requisite supports and services;
• Provide assistance to individuals with significant disabilities who are at risk of entering institutions so that the individuals may remain in the community, and
• Facilitate the transition of youth who are individuals with significant disabilities, who were eligible for individualized education programs under section 614(d) of the Individuals with Disabilities Act (20 U.S.C. 1414(d)), and who have completed their secondary education or otherwise left school, to postsecondary life.
ILA to track grant activities and create the annual reports, to Congress. ACL estimates the burden of this collection of information as follows: 56 SPIL respond annually which should be an average burden of 3,360 hours per State per year.
Food and Drug Administration, HHS.
Notice.
Statement of Organizations, Functions, and Delegations of Authority The Food and Drug Administration (FDA) is announcing that it has reorganized the Office of Foods and Veterinary Medicine (OFVM), Center for Food Safety and Applied Nutrition (CFSAN) by establishing the new Office of Dietary Supplement Programs (ODSP). ODSP will consist of the Evaluation and Research Staff and the Regulatory Implementation Staff. This reorganization resulted in the retitling of the OFVM, CFSAN, Office of Nutrition, Labeling and Dietary Supplements (ONLDS) to the Office of Nutrition and Food Labeling (ONFL), and the abolishment of the Division of Dietary Supplement Programs (DDSP) under ONLDS. This new organizational structure was approved by the Secretary of Health and Human Services on XXXXX and effective upon signature.
Helio Chaves, Acting Associate Director for Management, Center for Food Safety and Applied Nutrition, Office of Foods and Veterinary Medicine, Food and Drug Administration, 5100 Paint Branch Pkwy., College Park, MD 20740, 240-402-2471.
I. Part D, Chapter D-B, (Food and Drug Administration), the Statement of Organization, Functions, and Delegations of Authority for the Department of Health Human Services (35 FR 3685, February 25, 1970; 60 FR 56605, November 9, 1995; 64 FR 36361, July 6, 1999; 72 FR 50112, August 30, 2007; 74 FR 41713, August 18, 2009; and 76 FR 45270, July 28, 2011) is amended to reflect the transfer of DDSP functions and personnel into ODSP to better align the mission and day-to-day activities of DDSP. The reorganization brings more prominence to dietary supplements, which is a noteworthy interest to Congress, increasing the ability to recruit resources and expertise to ODSP, and allowing for a more strategic approach in how ODSP resources are utilized. ODSP will focus on ensuring the integrity of product identity, enhancing Good Manufacturing Practices (GMP) compliance even further through more enforcement and more education, increased attention to products with acute health hazards, finding efficiencies in New Dietary Ingredient (NDI) review process, and greater attention to claim substantiation. This reorganization is explained in Staff Manual Guides 1230A.1, 1231.20, and 1231.21.
FDA, OVFM, CFSAN has been restructured as follows:
II.
III.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of a meeting of the Board of Scientific Counselors, NIDCD.
The meeting will be closed to the public as indicated below in accordance with the provisions set forth in section 552b(c)(6), Title 5 U.S.C., as amended for the review, discussion, and evaluation of individual intramural programs and projects conducted by the National Institute on Deafness and Other Communication Disorders, including consideration of personnel qualifications and performance, and the competence of individual investigators, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Information is also available on the Institute's/Center's home page:
Notice is hereby given of a change in the meeting of the National Library of Medicine Special Emphasis Panel, February 25, 2016, 12:00 p.m. to 04:00 p.m., National Library of Medicine, 6705 Rockledge Drive, Suite 301, Bethesda, MD 20817 which was published in the
The meeting of the Special Emphasis Panel will be held on March 25, 2016 instead of February 25, 2016, at 12:00 p.m. and will end at 4:00 p.m. The meeting is closed to the public.
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 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.
U.S. Customs and Border Protection, Department of Homeland Security.
30-Day notice and request for comments; Extension of an existing collection of information.
U.S. Customs and Border Protection (CBP) of the Department of Homeland Security will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act: Application for Exportation of Articles under Special Bond (CBP Form 3495). This is a proposed extension of an information collection that was previously approved. CBP is proposing that this information collection be extended with no change to the burden hours or to the information collected. This document is
Written comments should be received on or before March 9, 2016 to be assured of consideration.
Interested persons are invited to submit written comments on this proposed information collection to the Office of Information and Regulatory Affairs, Office of Management and Budget. Comments should be addressed to the OMB Desk Officer for Customs and Border Protection, Department of Homeland Security, and sent via electronic mail to
Requests for additional information should be directed to Tracey Denning, U.S. Customs and Border Protection, Regulations and Rulings, Office of International Trade, 90 K Street NE., 10th Floor, Washington, DC 20229-1177, at 202-325-0265.
This proposed information collection was previously published in the
U.S. Customs and Border Protection, Department of Homeland Security.
General notice.
This notice advises the public that the quarterly Internal Revenue Service interest rates used to calculate interest on overdue accounts (underpayments) and refunds (overpayments) of customs duties remain unchanged from the previous quarter. For the calendar quarter beginning January 1, 2016, the interest rates for overpayments will be 2 percent for corporations and 3 percent for non-corporations, and the interest rate for underpayments will be 3 percent for both corporations and non-corporations. This notice is published for the convenience of the importing public and U.S. Customs and Border Protection personnel.
Michael P. Dean, Revenue Division, Collection and Refunds Branch, 6650 Telecom Drive, Suite #100, Indianapolis, Indiana 46278; telephone (317) 614-4882.
Pursuant to 19 U.S.C. 1505 and Treasury Decision 85-93, published in the
The interest rates are based on the Federal short-term rate and determined by the Internal Revenue Service (IRS) on behalf of the Secretary of the Treasury on a quarterly basis. The rates effective for a quarter are determined during the first-month period of the previous quarter.
In Revenue Ruling 2015-23, the IRS determined the rates of interest for the calendar quarter beginning January 1, 2016, and ending on March 31, 2016. The interest rate paid to the Treasury for underpayments will be the Federal short-term rate (1%) plus two percentage points (2%) for a total of three percent (3%) for both corporations and non-corporations. For corporate overpayments, the rate is the Federal short-term rate (1%) plus one percentage point (1%) for a total of two percent (2%). For overpayments made by non-corporations, the rate is the Federal short-term rate (1%) plus two percentage points (2%) for a total of three percent (3%). These interest rates are subject to change for the calendar quarter beginning April 1, 2016, and ending June 30, 2016.
For the convenience of the importing public and U.S. Customs and Border Protection personnel the following list of IRS interest rates used, covering the period from before July of 1974 to date, to calculate interest on overdue
U.S. Customs and Border Protection, Department of Homeland Security.
30-Day notice and request for comments; Extension of an existing collection of information.
U.S. Customs and Border Protection (CBP) of the Department of Homeland Security will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act: Country of Origin Marking Requirements for Containers or Holders. This is a proposed extension of an information collection that was previously approved. CBP is proposing that this information collection be extended with no change to the burden hours or to the information collected. This document is published to obtain comments from the public and affected agencies.
Written comments should be received on or before March 9, 2016 to be assured of consideration.
Interested persons are invited to submit written comments on this proposed information collection to the Office of Information and Regulatory Affairs, Office of Management and Budget. Comments should be addressed to the OMB Desk Officer for Customs and Border Protection, Department of Homeland Security, and sent via electronic mail to
Requests for additional information should be directed to Tracey Denning, U.S. Customs and Border Protection, Regulations and Rulings, Office of International Trade, 90 K Street NE., 10th Floor, Washington, DC 20229-1177, at 202-325-0265.
This proposed information collection was previously published in the
U.S. Customs and Border Protection, Department of Homeland Security.
Notice of approval of SGS North America, Inc., as a commercial gauger.
Notice is hereby given, pursuant to CBP regulations, that SGS North America, Inc., has been approved to gauge petroleum and certain petroleum products for customs purposes for the next three years as of April 29, 2015.
Approved Gauger and Accredited Laboratories Manager, Laboratories and Scientific Services Directorate, U.S. Customs and Border Protection, 1300 Pennsylvania Avenue NW., Suite 1500N, Washington, DC 20229, tel. 202-344-1060.
Notice is hereby given pursuant to 19 CFR 151.13, that SGS North America, Inc., 2800 Loop 197 South, Texas City, TX 77590, has been approved to gauge petroleum and certain petroleum products for customs purposes, in accordance with the provisions of 19 CFR 151.13. SGS North America, Inc., is approved for the following gauging procedures for petroleum and certain petroleum products set forth by the American Petroleum Institute (API):
Anyone wishing to employ this entity to conduct gauger services should request and receive written assurances from the entity that it is approved by the U.S. Customs and Border Protection to conduct the specific gauger service requested. Alternatively, inquiries regarding the specific gauger service this entity is approved to perform may be directed to the U.S. Customs and Border Protection by calling (202) 344-1060. The inquiry may also be sent to
U.S. Customs and Border Protection, Department of Homeland Security.
Notice of approval of SGS North America, Inc., as a commercial gauger.
Notice is hereby given, pursuant to CBP regulations, that SGS North America, Inc., has been approved to gauge petroleum and certain petroleum products for customs purposes for the next three years as of August 11, 2015.
Approved Gauger and Accredited Laboratories Manager, Laboratories and Scientific Services Directorate, U.S. Customs and Border Protection, 1300 Pennsylvania Avenue NW., Suite 1500N, Washington, DC 20229, tel. 202-344-1060.
Notice is hereby given pursuant to 19 CFR 151.13, that SGS North America, Inc., 4701 East Napoleon (Hwy 90), Sulphur, LA 70663, has been approved to gauge petroleum and certain petroleum products for customs purposes, in accordance with the provisions of 19 CFR 151.13. SGS North America, Inc., is approved for the following gauging procedures for petroleum and certain petroleum products set forth by the American Petroleum Institute (API):
Anyone wishing to employ this entity to conduct gauger services should request and receive written assurances from the entity that it is approved by the U.S. Customs and Border Protection to conduct the specific gauger service requested. Alternatively, inquiries regarding the specific gauger service this entity is approved to perform may be directed to the U.S. Customs and Border Protection by calling (202) 344-1060. The inquiry may also be sent to
National Protection and Programs Directorate, DHS.
30-day notice and request for comments; Extension of previously approved collection: 1670-0028.
The Department of Homeland Security Headquarters (DHS), National Protection and Programs Directorate (NPPD), Office of Infrastructure Protection (IP), Protective Security Coordination Division (PSCD), Office for Bombing Prevention (OBP) will submit the following Information Collection Request (ICR) to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995 (Pub. L. 104-13, 44 U.S.C. Chapter 35). NPPD is soliciting comments concerning New Information Collection Request—Technical Resource for Incident Prevention (TRIPwire) User Registration. DHS previously published this ICR in the
Comments are encouraged and will be accepted until March 9, 2016. This process is conducted in accordance with 5 CFR 1320.10.
Interested persons are invited to submit written comments on the proposed information collection to the Office of Information and Regulatory Affairs, OMB. Comments should be addressed to OMB Desk Officer, DHS, Office of Civil Rights and Civil Liberties. Comments must be identified by “DHS-2012-0022” and may be submitted by one of the following methods:
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OMB is particularly interested in comments that:
1. 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;
2. Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
3. Enhance the quality, utility, and clarity of the information to be collected; and
4. Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Dennis Malloy, DHS/NPPD/IP/PSCD/OBP,
TRIPWire is OBP's online, collaborative, information-sharing network for bomb squad, law enforcement, and other emergency services personnel to learn about current terrorist improvised explosive device (IED) tactics, techniques, and procedures, including
The information collected during the TRIPwire user registration process is reviewed electronically by the TRIPwire team to vet the user's “need to know,” which determines their eligibility for and access to TRIPwire. Memberships are re-verified annually based on the information users provide upon registration or communication with the TRIPwire help desk analysts. The information collected is for internal TRIPwire and OBP use only.
National Protection and Programs Directorate, DHS.
30-day notice and request for comments; Reinstatement, with change, of a previously approved collection: 1670-0009.
The Department of Homeland Security (DHS), National Protection and Programs Directorate (NPPD), Office of Infrastructure Protection (IP), Infrastructure Information Collection Division (IICD), Infrastructure Protection Gateway (IP Gateway) Program will submit the following Information Collection Request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995 (Pub. L. 104-13, 44 U.S.C. Chapter 35).
Comments are encouraged and will be accepted until March 9, 2016. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and questions about this Information Collection Request should be forwarded to DHS/NPPD/IP/IICD, 245 Murray Lane SW., Mail Stop 0602, Arlington, VA 20598-0602. Emailed requests should go to Kimberly Sass,
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The Office of Management and Budget is particularly interested in comments that:
1. Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
2. Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
3. Enhance the quality, utility, and clarity of the information to be collected; and
4. Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Kimberly Sass, DHS/NPPD/IP/IICD,
Under the direction of Homeland Security Presidential Directive-7 (2003), Presidential Policy Directive-21, and the National Infrastructure Protection Plan (NIPP 2013); NPPD/IP has developed the IP Gateway, a centrally managed repository of infrastructure capabilities allowing the Critical Infrastructure (CI) community to work in conjunction with each other toward the same goals. This collection encompasses three IP Gateway functions: General User Registration, Chemical Security Awareness Training Registration, and a User Satisfaction Survey. Upon requesting access to the IP Gateway, the multi-screen registration form requests the user's full name, work address, contact information Protected Critical Infrastructure (PCII) training status, citizenship status, supervisor and
National Protection and Programs Directorate, DHS.
30-Day notice and request for comments; New Information Collection Request: 1670—NEW.
The Department of Homeland Security (DHS), National Protection and Programs Directorate (NPPD), Office of Infrastructure Protection (IP), Protective Security Coordination Division (PSCD), Office for Bombing Prevention (OBP), will submit the following Information Collection Request (ICR) to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995 (Pub. L. 104-13, 44 U.S.C. Chapter 35). NPPD is soliciting comments concerning New Information Collection Request, Gratuitous Services Agreement and Volunteer Release and Hold Harmless form. DHS previously published this ICR in the
Comments are encouraged and will be accepted until March 9, 2016. This process is conducted in accordance with 5 CFR 1320.10.
Interested persons are invited to submit written comments on the proposed information collection to DHS/NPPD/IP/PSCD/OBP, 245 Murray Lane SW., Mail Stop 0612, Washington, DC 20528-0612. Emailed requests should go to
•
•
•
OMB is particularly interested in comments that:
1. 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;
2. Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
3. Enhance the quality, utility, and clarity of the information to be collected; and
4. Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
DHS/NPPD/IP/PSCD/OBP, 245 Murray Lane SW., Mail Stop 0612, Washington, DC 20528-0612 or
The Gratuitous Services Agreement and Volunteer Release and Hold Harmless form will be provided to participants of OBP trainings. The participants will be emergency response personnel training with DHS OBP personnel. The collection of this information is necessary in the case that an individual who acts as a volunteer role player in support of official OBP training sustains an injury or death during the performance of his or her supporting role. If legal action is taken, this information can serve as a “hold harmless” statement/agreement by the Government. The purpose of the Gratuitous Services Agreement is to establish that no monies, favors or other compensation will be given or received by either parties involved.
Transportation Security Administration, DHS.
30-Day notice.
This notice announces that the Transportation Security Administration (TSA) has forwarded the Information Collection Request (ICR), Office of Management and Budget (OMB) control number 1652-0053, abstracted below to OMB for renewal in compliance with the Paperwork Reduction Act. The ICR describes the nature of the information collection and its expected burden. TSA published a
Send your comments by March 9, 2016. A comment to OMB is most effective if OMB receives it within 30 days of publication.
Interested persons are invited to submit written comments on the proposed information collection to the Office of Information and Regulatory Affairs, OMB. Comments should be addressed to Desk Officer, Department of Homeland Security/TSA, and sent via electronic mail to
Christina A. Walsh, TSA PRA Officer, Office of Information Technology (OIT), TSA-11, Transportation Security Administration, 601 South 12th Street, Arlington, VA 20598-6011; telephone (571) 227-2062; email
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
(1) Evaluate whether the proposed information requirement is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agency's estimate of the burden;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including using appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology.
U.S. Citizenship and Immigration Services, Department of Homeland Security.
30-Day notice.
The Department of Homeland Security (DHS), U.S. Citizenship and Immigration Services (USCIS) will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection notice was previously published in the
The purpose of this notice is to allow an additional 30 days for public comments. Comments are encouraged
Written comments and/or suggestions regarding the item(s) contained in this notice, especially regarding the estimated public burden and associated response time, must be directed to the OMB USCIS Desk Officer via email at
You may wish to consider limiting the amount of personal information that you provide in any voluntary submission you make. For additional information please read the Privacy Act notice that is available via the link in the footer of
USCIS, Office of Policy and Strategy, Regulatory Coordination Division, Samantha Deshommes, Acting Chief, 20 Massachusetts Avenue NW., Washington, DC 20529-2140, Telephone number (202) 272-8377 (This is not a toll-free number. Comments are not accepted via telephone message). Please note contact information provided here is solely for questions regarding this notice. It is not for individual case status inquiries. Applicants seeking information about the status of their individual cases can check Case Status Online, available at the USCIS Web site at
You may access the information collection instrument with instructions, or additional information by visiting the Federal eRulemaking Portal site at:
(1) 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;
(2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Office of the Assistant Secretary for Housing—Federal Housing Commissioner, HUD.
Notice.
HUD is seeking approval from the Office of Management and Budget (OMB) for the information collection described below. In accordance with the Paperwork Reduction Act, HUD is requesting comment from all interested parties on the proposed collection of information. The purpose of this notice is to allow for 60 days of public comment.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB Control Number and should be sent to: Colette Pollard, Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 7th Street SW., Room 4176, Washington, DC 20410-5000; telephone 202-402-3400 (this is not a toll-free number) or email at
Theodore F. Toon, Director Multifamily
Copies of available documents submitted to OMB may be obtained from Ms. Pollard.
This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.
This notice is soliciting comments from members of the public and affected parties concerning the collection of information described in Section A on the following:
(1) 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;
(2) The accuracy of the agency's estimate of the burden of the proposed collection of information;
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) Ways to minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
HUD encourages interested parties to submit comment in response to these questions.
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35.
Office of the Assistant Secretary for Policy Development and Research, HUD.
Notice of Final Fiscal Year (FY) 2016 Fair Market Rents (FMRs), Update.
Today's notice updates the FY 2016 FMRs for Oakland-Fremont, CA HUD Metro FMR Area, based on surveys conducted in December 2015 by the area public housing agencies (PHAs). The FY 2016 FMRs for these areas reflect the estimated 40th percentile rent levels trended to April 1, 2016.
For technical information on the methodology used to develop FMRs or a listing of all FMRs, please call the HUD USER information line at 800-245-2691 or access the information on the HUD USER Web site:
Questions related to use of FMRs or voucher payment standards should be directed to the respective local HUD program staff. Questions on how to conduct FMR surveys or concerning further methodological explanations may be addressed to Marie L. Lihn or Peter B. Kahn, Economic and Market Analysis Division, Office of Economic Affairs, Office of Policy Development and Research, telephone 202-402-2409. Persons with hearing or speech impairments may access this number through TTY by calling the toll-free Federal Relay Service at 800-877-8339. (Other than the HUD USER information line and TDD numbers, telephone numbers are not toll-free.)
The FMRs appearing in the following table supersede the values found in Schedule B that became effective on December 11, 2015, and were printed in the December 11, 2015
The FMRs for the affected area are revised as follows:
Office of the Assistant Secretary for Public and Indian Housing, PIH, HUD.
Notice.
HUD is seeking approval from the Office of Management and Budget (OMB) for the information collection described below. In accordance with the Paperwork Reduction Act, HUD is requesting comment from all interested parties on the proposed collection of information. The purpose of this notice is to allow for 60 days of public comment.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB Control Number and should be sent to: Colette Pollard, Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 7th Street SW., Room 4176, Washington, DC 20410-5000; telephone 202-402-3400 (this is not a toll-free number) or email at
Arlette Mussington, Office of Policy, Programs and Legislative Initiatives, PIH, Department of Housing and Urban Development, 451 7th Street SW., (L'Enfant Plaza, Room 2206), Washington, DC 20410; telephone 202-402-4109, (this is not a toll-free number). Persons with hearing or speech impairments may access this number via TTY by calling the Federal Information Relay Service at (800) 877-8339. Copies of available documents submitted to OMB may be obtained from Ms. Mussington.
This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.
This notice is soliciting comments from members of the public and affected parties concerning the collection of information described in Section A on the following:
(1) 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;
(2) The accuracy of the agency's estimate of the burden of the proposed collection of information;
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) Ways to minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
HUD encourages interested parties to submit comment in response to these questions.
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35.
The Office of Community Planning and Development, HUD
Notice.
HUD is seeking approval from the Office of Management and Budget (OMB) for the information collection described below. In accordance with the Paperwork Reduction Act, HUD is requesting comment from all interested parties on the proposed collection of information. The purpose of this notice is to allow for 60 days of public comment.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB Control Number and should be sent to: Colette Pollard, Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 7th Street SW., Room 4176, Washington, DC 20410-5000; telephone 202-402-3400 (this is not a toll-free number) or email at
David Enzel, Director, OTAM, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410; email
Copies of available documents submitted to OMB may be obtained from Ms. Pollard.
This notice informs the public that HUD is seeking approval from OMB for the
This notice is soliciting comments from members of the public and affected parties concerning the collection of information described in Section A on the following:
(1) 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;
(2) The accuracy of the agency's estimate of the burden of the proposed collection of information;
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) Ways to minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
HUD encourages interested parties to submit comment in response to these questions.
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35.
Fish and Wildlife Service, Interior.
Notice; request for comments.
We (U.S. Fish and Wildlife Service) have sent an Information Collection Request (ICR) to OMB for review and approval. We summarize the ICR below and describe the nature of the collection and the estimated burden and cost. 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.
You must submit comments on or before March 9, 2016.
Send your comments and suggestions on this information collection to the Desk Officer for the Department of the Interior at OMB-OIRA at (202) 395-5806 (fax) or
To request additional information about this ICR, contact Hope Grey at
It is for these reasons that we plan to use a quantitative survey to collect information on the attitudes that the public maintains towards the natural environment; the effects of contact with nature on participants' health and quality of life; the extent of contact with nature and obstacles to greater contact with nature; general knowledge of nature and wildlife; concerns toward selected environmental issues; and socio-demographic variables. Results will help improve the design and delivery of new or existing programs aimed at engaging the public in nature-related activities (
On May 19, 2015, we published in the
We again 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. 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 OMB and us in your comment to withhold your personal identifying information from public review, we cannot guarantee that it will be done.
Office of the Secretary, Interior.
Notice.
The Indian Gaming Regulatory Act provides for a three-person National Indian Gaming Commission. One member, the Chair, is appointed by the President with the advice and consent of the Senate. Two associate members are appointed by the Secretary of the Interior (Secretary). Before appointing members, the Secretary is required to provide public notice of a proposed appointment and allow a comment period. Notice is hereby given of the proposed appointment of Kathryn Isom-Clause as an associate member of the National Indian Gaming Commission for a term of 3 years.
Submit comments on or before March 9, 2016.
Send comments to the Director, Office of the Executive Secretariat and Regulatory Affairs, U.S. Department of the Interior, 1849 C Street NW., Mail Stop 7328, Washington, DC 20240.
Mr. Michael Hoenig, National Indian Gaming Commission, c/o Department of the Interior, 1849 C Street NW., Mail Stop 1621, Washington, DC 20240; telephone (202) 632-7003; facsimile (202) 632-7066.
The Indian Gaming Regulatory Act, 25 U.S.C. 2701
The Secretary proposes to appoint Kathryn Isom-Clause as an associate member of the Commission for a term of 3 years. Ms. Isom-Clause is a citizen of the Taos Pueblo and is well qualified to be a member of the National Indian Gaming Commission by virtue of her extensive background and experience in Indian gaming, as well as a broad spectrum of other Native American issues.
In her current position as Senior Counselor to the Assistant Secretary—Indian Affairs at the Department of the Interior, Ms. Isom-Clause provides policy guidance to the Assistant Secretary on gaming matters, including the review and analysis of revenue allocation plans, tribal-state gaming compacts, and environmental compliance issues. In addition to her work on gaming issues, Ms. Isom-Clause chairs and participates on a number of working groups and committees covering a variety of issues important to Indian Affairs. Before serving as Senior Counselor to the Assistant Secretary—Indian Affairs, Ms. Isom-Clause served as an attorney representing tribal clients throughout the United States.
Ms. Isom-Clause's experience with Indian gaming specifically, as well as her wide experience in Federal Indian law and policy, makes her a highly qualified candidate for membership on the National Indian Gaming Commission. Her extensive knowledge and experience will enrich the Commission's deliberations and contribute to informed decisions that promote the integrity and economic viability of Indian gaming.
Ms. Isom-Clause does not have any financial interests that would make her ineligible to serve on the Commission under 25 U.S.C. 2704(b)(5)(B) or (C).
Any person wishing to submit comments on this proposed appointment of Kathryn Isom-Clause may submit written comments to the address listed above. Comments must be received by March 9, 2016.
Office of Surface Mining Reclamation and Enforcement, Interior.
Reopening of the public comment period.
On December 11, 2015, the Office of Surface Mining Reclamation and Enforcement (OSMRE) announced the availability for public review and comment of the draft Petition Evaluation Document and Environmental Impact Statement (PED/EIS) for the North Cumberland Wildlife Management Area Petition to Find Certain Lands Unsuitable for Surface Coal Mining Operations. The comment period ended on January 25, 2016. After receiving multiple requests for additional time to prepare and submit comments, OSMRE has decided to reopen the comment period for submitting comments regarding the draft PED/EIS. The comment period is reopened through February 26, 2016.
Comments may be submitted using any of the following methods:
You may review the draft PED/EIS online at
Earl D. Bandy Jr., Director—Knoxville Field Office, Office of Surface Mining Reclamation and Enforcement, John J. Duncan Federal Building, 710 Locust Street, 2nd Floor, Knoxville, Tennessee 37902. Telephone: 865-545-4103. Email:
On December 11, 2015, OSMRE announced the availability for public review and comment of the draft Petition Evaluation Document and Environmental Impact Statement for the North Cumberland Wildlife Management Area Petition to Find Certain Lands Unsuitable for Surface Coal Mining Operations. 80 FR 77018 (Dec. 11, 2015). The notice provided for the submission of comments by January 25, 2016.
OSMRE received multiple requests, including a letter from five members of the Tennessee Congressional Delegation, that OSMRE provide additional time for the public to prepare and submit comments. In response to these requests, OSMRE is reopening the public comment period to allow interested parties to provide OSMRE with written comments in response to the draft PED/EIS.
OSMRE will consider any comments in response to the draft PED/EIS received by midnight of February 26, 2016, and deems any comments received by that time to be timely submitted.
40 CFR 1506.1, 40 CFR 1506.6.
On the basis of the record
The Commission, pursuant to section 751(c) of the Tariff Act of 1930 (19 U.S.C. 1675(c)), instituted this review on September 1, 2015 (80 FR 52743) and determined on December 7, 2015 that it would conduct an expedited review (80 FR 79097, December 18, 2015).
The Commission made this determination pursuant to section 751(c) of the Tariff Act of 1930 (19 U.S.C. 1675(c)). It completed and filed its determination in this review on February 2, 2016.
By order of the Commission.
U.S. International Trade Commission.
Notice.
Notice is hereby given that the U.S. International Trade Commission has received a complaint entitled
Lisa R. Barton, Secretary to the Commission, U.S. International Trade Commission, 500 E Street, SW., Washington, DC 20436, telephone (202) 205-2000. The public version of the complaint can be accessed on the Commission's Electronic Document Information System (EDIS) at EDIS.
General information concerning the Commission may also be obtained by accessing its Internet server at United States International Trade Commission (USITC) at USITC.
The Commission has received a complaint and a submission pursuant to section 210.8(b) of the Commission's Rules of Practice and Procedure filed on behalf of Stryker Corporation on February 1, 2016. The complaint alleges violations of section 337 of the Tariff Act of 1930 (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 hospital beds, and components thereof. The complaint names as respondents Umano Médical Inc. of Canada; and Umano Médical World Inc. of Canada. The complainant requests that the Commission issue a limited exclusion order, a cease and desist order, and impose a bond upon respondents' alleged infringing articles during the 60-day Presidential review period pursuant to 19 U.S.C. 1337(j).
Proposed respondents, other interested parties, and members of the public are invited to file comments, not to exceed five (5) pages in length, inclusive of attachments, on any public interest issues raised by the complaint or section 210.8(b) filing. Comments should address whether issuance of the relief specifically requested by the complainant in this investigation would affect the public health and welfare in the United States, competitive conditions in the United States economy, the production of like or directly competitive articles in the United States, or United States consumers.
In particular, the Commission is interested in comments that:
(i) Explain how the articles potentially subject to the requested remedial orders are used in the United States;
(ii) identify any public health, safety, or welfare concerns in the United States relating to the requested remedial orders;
(iii) identify like or directly competitive articles that complainant, its licensees, or third parties make in the United States which could replace the subject articles if they were to be excluded;
(iv) indicate whether complainant, complainant's licensees, and/or third party suppliers have the capacity to replace the volume of articles potentially subject to the requested exclusion order and/or a cease and desist order within a commercially reasonable time; and
(v) explain how the requested remedial orders would impact United States consumers.
Written submissions must be filed no later than by close of business, eight calendar days after the date of publication of this notice in the
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 docket number (“Docket No. 3117”) 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.
This action is taken under the authority of section 337 of the Tariff Act of 1930, as amended (19 U.S.C. 1337), and of sections 201.10 and 210.8(c) of the Commission's Rules of Practice and Procedure (19 CFR 201.10, 210.8(c)).
By order of the Commission.
Bureau of Justice Statistics, Department of Justice.
60-Day notice.
The Department of Justice (DOJ), Office of Justice Programs, Bureau of Justice Statistics, will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995.
Comments are encouraged and will be accepted for 60 days until April 8, 2016.
If you have additional comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Shelley S. Hyland, Statistician, Bureau of Justice Statistics, 810 Seventh Street NW., Washington, DC 20531 (email:
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
Overview of this information collection:
(1)
(2)
(3)
(4)
(5)
(6)
If additional information is required contact: Jerri Murray, Department Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Two Constitution Square, 145 N Street NE., 3E.405B, Washington, DC 20530.
Federal Bureau of Investigation, Department of Justice.
60-day notice.
The Department of Justice (DOJ), Office of Justice Programs, Bureau of Justice Statistics, will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995.
Comments are encouraged and will be accepted for 60 days until April 8, 2016.
If you have additional comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Brandon S. Seifert, Management and Program Analyst, Federal Bureau of Investigation, Criminal Justice Information Services (CJIS) Division, NICS section, Module A-3, 1000 Custer Hollow Road, Clarksburg, West Virginia 26306, or facsimile at (304) 625-7540.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
Overview of this information collection:
1.
2.
3.
4.
Primary: Any Federal Firearms Licensee (FFL) or State Point of Contact (POC) requesting access to conduct National Instant Criminal Background Check Systems (NICS) checks telephonically or by the Internet through the NICS E-Check.
Abstract: The Brady Handgun Violence Prevention Act of 1993 required the United States Attorney General to establish a national instant criminal background check system that any FFL may contact, by telephone or by other electronic means, for information to be supplied immediately, on whether receipt of a firearm to a prospective purchaser would violate state or federal law. Information pertaining to licensees who may contact the NICS is being collected to manage and control access to the NICS and to the NICS E-Check, to ensure appropriate resources are available to support the NICS and also to ensure the privacy and security of NICS information.
5.
The completion of the Federal Firearms Licensee (FFL) Officer/Employee Acknowledgment of Responsibilities under the NICS form is estimated to take approximately three minutes to read the responsibilities and two minutes to complete the form, for a total of five minutes. The average hour burden for this specific forms is 6,000 × 5 minutes/60 = 250 hours.
6.
If additional information is required contact: Jerri Murray, Department Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Two Constitution Square, 145 N Street NE., 3E.405B, Washington, DC 20530.
Notice.
The Department of Labor is submitting the Office of the Assistant Secretary for Administration and Management (OASAM) sponsored information collection request (ICR) revision titled, “Department of Labor Generic Solution for “Touch-Base” Activities,” to the Office of Management and Budget (OMB) for review and approval for use in accordance with the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501
The OMB will consider all written comments that agency receives on or before March 9, 2016.
A copy of this ICR with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained free of charge from the RegInfo.gov Web site at
Submit comments about this request by mail or courier to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for DOL-OASAM, Office of Management and Budget, Room 10235, 725 17th Street NW., Washington, DC 20503; by Fax: 202-395-5806 (this is not a toll-free number); or by email:
Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to
44 U.S.C. 3507(a)(1)(D).
This ICR seeks approval under the PRA for revisions to the Department of Labor Generic Solution for “Touch-Base” Activities information collection. This information collection activity provides a means to garner qualitative customer and stakeholder feedback in an efficient, timely manner. Feedback will provide insights into customer or stakeholder perceptions, experiences and expectations, provide an early warning of issues interest, or focus attention on areas where communication, training, or changes in operations or policy might improve delivery of products, services, or Federal policy. These collections will allow for ongoing, collaborative, and actionable communications between the DOL and its customers and stakeholders. Information collected will also allow feedback to contribute directly to the improvement of program management. This ICR would revise the collection to clarify that it may be used to obtain information to assist policy choices and would be similar to an ICR approved specifically for the Employment and Training Administration that is designed to get quick feedback on issues of interest to that agency.
This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless it is approved by the OMB under the PRA and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information that does not display a valid Control Number.
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Notice.
The Department of Labor (DOL) is submitting the Mine Safety and Health Administration (MSHA) sponsored information collection request (ICR) titled, “Petitions for Modification of Mandatory Safety Standards” to the Office of Management and Budget (OMB) for review and approval for continued use, without change, in accordance with the Paperwork Reduction Act of 1995 (PRA), 44 U.S.C. 3501
The OMB will consider all written comments that agency receives on or before March 9, 2016.
A copy of this ICR with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained free of charge from the RegInfo.gov Web site at:
Submit comments about this request by mail or courier to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for DOL-MSHA, Office of Management and Budget, Room 10235, 725 17th Street NW., Washington, DC 20503; by Fax: 202-395-5806 (this is not a toll-free number); or by email:
Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or by email at
44 U.S.C. 3507(a)(1)(D).
This ICR seeks to extend PRA authority for the Petitions for Modification of Mandatory Safety Standards information collection requirements codified in regulations 30 CFR 44.9, 44.10, and 44.11 that provide procedures by which a mine operator, a representative of miners, or an independent contractor may request relief from a mandatory safety standard. Federal Mine Safety and Health Act of 1977 sections 101(a) and (c) and 103(h) authorize this information collection.
This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless it is approved by the OMB under the PRA and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information that does not display a valid Control Number.
The DOL seeks to extend PRA authorization for this information collection for three (3) more years, without any change to existing requirements. The DOL notes that existing information collection requirements submitted to the OMB receive a month-to-month extension while they undergo review. For additional substantive information about this ICR, see the related notice published in the
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Notice.
The Department of Labor (DOL) is submitting the Employment and Training Administration (ETA) sponsored information collection request (ICR) revision titled, “Short-Time Compensation Grants,” to the Office of Management and Budget (OMB) for review and approval for use
The OMB will consider all written comments that agency receives on or before March 9, 2016.
A copy of this ICR with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained free of charge from the RegInfo.gov Web site at
Submit comments about this request by mail or courier to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for DOL-ETA, Office of Management and Budget, Room 10235, 725 17th Street NW., Washington, DC 20503; by Fax: 202-395-5806 (this is not a toll-free number); or by email:
Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to
44 U.S.C. 3507(a)(1)(D).
This ICR seeks approval under the PRA for revisions to the Short-Time Compensation (STC) Grants information collection. Middle Class Tax Relief and Job Creation Act of 2012, Subtitle D, Short-Time Compensation Program, also known as the Layoff Prevention Act of 2012, concerns States that currently participate in, or wish to initiate a layoff aversion program known as STC or work-sharing. The law requires applications, administrative processes, monitoring, and reporting of data between State Workforce Agencies (SWAs) and the ETA. The ETA has principal oversight responsibility for the Unemployment Insurance (UI) program that SWAs operate. The ETA has developed a data collection for the proper oversight of State STC programs to ensure compliance with the UI system funding and administration under the Layoff Prevention Act. This information collection has been classified as a revision, because information collected related to the temporary financing of STC payments by the Federal Government, applying for an STC grant(s), and applying to operate a temporary Federal STC program (for states without STC programs in state law) were removed. The information collection is no longer necessary for the ETA to carry out its authority.
This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless it is approved by the OMB under the PRA and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information that does not display a valid Control Number.
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Notice.
The Department of Labor (DOL) is submitting the Employment and Training Administration (ETA) sponsored information collection request (ICR) revision titled, “Self-Employment Training Demonstration Evaluation,” to the Office of Management and Budget (OMB) for review and approval for use in accordance with the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501
The OMB will consider all written comments that agency receives on or before March 9, 2016.
A copy of this ICR with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained free of charge from the RegInfo.gov Web site at
Submit comments about this request by mail or courier to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for DOL-ETA, Office of Management and Budget, Room 10235, 725 17th Street NW., Washington, DC 20503; by Fax: 202-395-5806 (this is not a toll-free number); or by email:
Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to
44 U.S.C. 3507(a)(1)(D).
This ICR seeks approval under the PRA for revisions to the Self-Employment Training (SET) Demonstration Evaluation. More specifically, clearance is being requested for an extension to continue administering a follow-up survey. This ICR proposes no changes to the data collection instrument. This information collection has been classified as a revision, because other information collections that are currently approved are no longer needed and will be discontinued.
This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless it is approved by the OMB under the PRA and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information that does not display a valid Control Number.
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
National Science Foundation.
Notice and request for comments.
The National Science Foundation (NSF) is announcing plans to request clearance of this collection. In accordance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 (Pub. L. 104-13), we are providing opportunity for public comment on this action. After obtaining and considering public comment, NSF will prepare the submission requesting that OMB approve clearance of this collection for no longer than three years.
Written comments on this notice must be received by April 8, 2016 to be assured of consideration. Comments received after that date will be considered to the extent practicable.
Contact Suzanne H. Plimpton, Reports Clearance Officer, National Science Foundation, 4201 Wilson Boulevard, Suite 295, Arlington, Virginia 22230; telephone (703) 292-7556; or send email to
The mission of the National Science Foundation (NSF) is to promote the progress of science; to advance the national health, welfare, and prosperity; and to secure the national defense, while avoiding the undue concentration of research and education. In 1977, in response to congressional concern that NSF funding was overly concentrated geographically, a National Science
The EPSCoR Research Infrastructure Improvement Programs advance science and engineering capabilities in EPSCoR jurisdictions for discovery, innovation and overall knowledge-based prosperity. These projects build human, cyber, and physical infrastructure in EPSCoR jurisdictions, stimulating sustainable improvements in their Research & Development (R&D) capacity and competitiveness.
EPSCoR projects are unique in their scope and complexity; in their integration of individual researchers, institutions, and organizations; and in their role in developing the diverse, well-prepared, STEM-enabled workforce necessary to sustain research competitiveness and catalyze economic development. In addition, these projects are generally inter- (ormulti-)disciplinary and involve effective jurisdictional and regional collaborations among academic, government and private sector stakeholders that advance scientific research, promote innovation and provide multiple societal benefits; and they broaden participation in science and engineering by engaging multiple institutions and organizations at all levels of research and education, and people within and among EPSCoR jurisdictions. These projects usually involve between 100 (Track-2) to 300 (Track-1) participants per year over the performance period and provide outreach experiences to thousands ofK-12 students and teachers. America COMPETES Reauthorization Act of 2010, Section 517 (H.R. 5116, Section 517) requires NSF EPSCoR to submit annual reports to both Congress and OSTP that contains data detailing project progress and success (new investigators, broadening participation, dissemination of results, new workshops, outreach activities, proposals submitted and awarded, mentoring activities among faculty members, collaborations, researcher participating on the review process, etc.).
EPSCoR RII Track-1 and Track-2 projects are required to submit annual reports on progress and plans, which are used as a basis for performance review and determining the level of continued funding. To support this review and the management of an EPSCoR RII projects, teams are required to develop a set of performance indicators for building sustainable infrastructure and capacity in terms of a strategic plan for the project; measure performance and revise strategies as appropriate; report on the progress relative to the project's goals and milestones; and describe changes in strategies, if any, for submission annually to NSF. These indicators are both quantitative and descriptive and may include, for example, the characteristics of project personnel and students; aggregate demographics of participants; sources of financial support and in-kind support; expenditures by operational component; characteristics of industrial and/or other sector participation; research activities; workforce development activities; external engagement activities; patents and patent licenses; publications; degrees granted to students involved in project activities; and descriptions of significant advances and other outcomes of the EPSCoR project's efforts. Part of this reporting takes the form of several spreadsheets to capture specific information to demonstrate progress towards achieving the goals of the program. Such reporting requirements are included in the cooperative agreement which is binding between the awardee institution and NSF.
Each project's annual report addresses the following categories of activities: (1) Research, (2) education, (3) workforce development, (4) partnerships and collaborations, (5) communication and dissemination, (6) sustainability, (7) diversity, (8) management, and (9) evaluation and assessment.
For each of the categories the report is required to describe overall objectives for the year; specific accomplishments, impacts, outputs and outcomes; problems or challenges the project has encountered in making progress towards goals; and anticipated problems in performance during the following year.
The current RPPR is designed primarily to support reporting from individual investigators and nor for large centers/center-like programs involving hundreds of participants. The change would facilitate reporting better aligned with program goals and is expected to minimize reporting burden on the EPSCoR community and provide data as legislatively required for NSF EPSCoR.
Nuclear Regulatory Commission.
Application for direct transfer of licenses; 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 a direct license transfer application filed by Luminant Generation Company, LLC (Luminant Power) on November 12, 2015, and supplemented by letter dated December 9, 2015. The application seeks NRC approval of the direct transfer of Facility
Comments must be filed by March 9, 2016. A request for a hearing must be filed by February 29, 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 the Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-3016, email:
Please refer to Docket ID NRC-2016-0020 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-2016-0020 in the subject line of your comment submission.
The NRC cautions you not to include identifying or contact information that you do not want to be publicly disclosed in your comment submission. The NRC will post all comment submissions at
If you are requesting or aggregating comments from other persons for submission to the NRC, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that the NRC does not routinely edit comment submissions to remove such information before making the comment submissions available to the public or entering the comment into ADAMS.
The NRC is considering the issuance of an order under § 50.80 of title 10 of the
Following approval of the proposed direct transfer of control of the license, CP LLC would acquire ownership of the facility. OpCo LLC would be responsible for the operation and maintenance of CPNPP and ISFSI. Current Luminant Power nuclear management and technical personnel will be employed by OpCo LLC. Accordingly, there will be no change in management and/or technical qualifications, and OpCo LLC will continue to be technically qualified to operate the facility.
No physical changes to the CPNPP and ISFSI 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
Before issuance of the proposed conforming license amendment, the Commission will have made findings required by the Atomic Energy Act of 1954, as amended (AEA), and the Commission's regulations.
As provided in 10 CFR 2.1315, unless otherwise determined by the Commission with regard to a specific application, the Commission has determined that any amendment to the license of a utilization facility or to the license of an ISFSI, which does no more than conform the license to reflect the transfer action, involves no significant hazards consideration and no genuine issue as to whether the health and safety of the public will be significantly affected. No contrary determination has been made with respect to this specific license amendment application. In light of the generic determination reflected in 10 CFR 2.1315, no public comments with respect to significant hazards considerations are being solicited, notwithstanding the general comment procedures contained in 10 CFR 50.91.
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(s) whose interest may be affected by this action may file a request for a hearing and a petition to intervene with respect to issuance of the amendment to the subject facility operating license or combined license. Requests for a hearing and a petition for leave to intervene shall be filed in accordance with the Commission's “Agency Rules of Practice and Procedure” in 10 CFR part 2. Interested person(s) should consult a current copy of 10 CFR 2.309, which is available at the NRC's PDR, located at One White Flint North, Room O1-F21, 11555 Rockville Pike (first floor), Rockville, Maryland 20852. The NRC's regulations are accessible electronically from the NRC Library on the NRC's Web site at
As required by 10 CFR 2.309, a petition for leave to intervene shall set forth with particularity the interest of the petitioner in the proceeding, and how that interest may be affected by the results of the proceeding. The petition should specifically explain the reasons why intervention should be permitted with particular reference to the following general requirements: (1) The name, address, and telephone number of the requestor or petitioner; (2) the nature of the requestor's/petitioner's right under the Act to be made a party to the proceeding; (3) the nature and extent of the requestor's/petitioner's property, financial, or other interest in the proceeding; and (4) the possible effect of any decision or order which may be entered in the proceeding on the requestor's/petitioner's interest. The petition must also set forth the specific contentions which the requestor/petitioner seeks to have litigated at the proceeding.
Each contention must consist of a specific statement of the issue of law or fact to be raised or controverted. In addition, the requestor/petitioner shall provide a brief explanation of the bases for the contention and a concise statement of the alleged facts or expert opinion which support the contention and on which the requestor/petitioner intends to rely in proving the contention at the hearing. The requestor/petitioner must also provide references to those specific sources and documents of which the petitioner is aware and on which the requestor/petitioner intends to rely to establish those facts or expert opinion. The petition must include sufficient information to show that a genuine dispute exists with the applicant on a material issue of law or fact. Contentions shall be limited to matters within the scope of the amendment under consideration. The contention must be one which, if proven, would entitle the requestor/petitioner to relief. A requestor/petitioner who fails to satisfy these requirements with respect to at least one contention will not be permitted to participate as a party.
Those permitted to intervene become parties to the proceeding, subject to any limitations in the order granting leave to intervene, and have the opportunity to participate fully in the conduct of the hearing with respect to resolution of that person's admitted contentions, including the opportunity to present evidence and to submit a cross-examination plan for cross-examination of witnesses, consistent with NRC regulations, policies and procedures.
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)-(iii).
If a hearing is requested, and the Commission has not made a final determination on the issue of no significant hazards consideration, the Commission will make a final determination on the issue of no significant hazards consideration. The final determination will serve to decide when the hearing is held. If the final determination is that the amendment request involves no significant hazards consideration, the Commission may issue the amendment and make it immediately effective, notwithstanding the request for a hearing. Any hearing held would take place after issuance of the amendment. If the final determination is that the amendment request involves a significant hazards consideration, then any hearing held would take place before the issuance of any amendment unless the Commission finds an imminent danger to the health or safety of the public, in which case it will issue an appropriate order or rule under 10 CFR part 2.
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 February 29, 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 for leave to intervene set forth in this
If a hearing is granted, any person who does not wish, or is not qualified, to become a party to the proceeding may, in the discretion of the presiding officer, be permitted to make a limited appearance pursuant to the provisions of 10 CFR 2.315(a). A person making a limited appearance may make an oral or written statement of position on the issues, but may not otherwise participate in the proceeding. A limited appearance may be made at any session of the hearing or at any prehearing conference, subject to the limits and conditions as may be imposed by the presiding officer. Persons desiring to make a limited appearance are requested to inform the Secretary of the Commission by February 29, 2016.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding prior to the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC's E-Filing rule (72 FR 49139; August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, at least 10 days prior to the filing deadline, the participant should contact the Office of the Secretary by email at
Information about applying for a digital ID certificate is available on the NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's online, Web-based submission form. In order to serve documents through the Electronic Information Exchange System, users will be required to install a Web browser plug-in from the NRC's Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be in Portable Document Format (PDF) in accordance with NRC guidance available on the NRC's public Web site at
A person filing electronically using the NRC's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC's public Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by first-class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service upon depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket which is available to the public at
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 letters dated November 12 and December 9, 2015.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Environmental assessment and finding of no significant impact; issuance.
The U.S. Nuclear Regulatory Commission (NRC) is issuing an environmental assessment (EA) and a finding of no significant impact (FONSI) for its review and approval of the decommissioning funding plan submitted by Portland General Electric Company (PGE), on December 13, 2012, for the Trojan independent spent fuel storage installation (ISFSI).
Please refer to Docket ID NRC-2016-0021 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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Jose Cuadrado, Office of Nuclear Material Safety and Safeguards, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-0606, email:
The NRC is considering the approval of the decommissioning funding plan (DFP) for the Trojan ISFSI. Portland General Electric Company (PGE), submitted its DFP for NRC's review and approval by letter dated December 13, 2012 (ADAMS Accession No. ML12355A286). The NRC staff has prepared an EA (ADAMS Accession No. ML16029A242) in support of its review of PGE's DFP, in accordance with the NRC's regulations in part 51 of title 10 of the
The Trojan ISFSI is located on the Trojan Nuclear Plant site, in Columbia County, Oregon, approximately 42 miles north of the city of Portland, Oregon. Portland General Electric Company (PGE) is authorized by the NRC, under License No. SNM-2509, to store spent nuclear fuel at the Trojan ISFSI.
The NRC requires its licensees to plan for the eventual decommissioning of their licensed facilities prior to license termination. On June 17, 2011; 76 FR 35512, the NRC published a final rule in the
The proposed federal action is the NRC's review and approval of PGE's DFP submitted in accordance with 10 CFR 72.30(b). In order to approve the DFP, the NRC will evaluate (i) whether the decommissioning cost estimate (DCE) adequately estimates the cost to conduct the required ISFSI decommissioning activities prior to license termination, including identification of the volume of onsite subsurface material containing residual radioactivity that will require remediation to meet the license termination criteria in 10 CFR 20.1402 or 10 CFR 20.1403, and (ii) whether the aggregate dollar amount of PGE's financial instruments provide adequate
The proposed action does not require any changes to the ISFSI's licensed routine operations, maintenance activities, or monitoring programs, nor does it require any new construction or land disturbing activities. The scope of the proposed action concerns only the NRC's review and approval of the PGE's DFP. The scope of the proposed action does not include, and will not result in, the review and approval of any decontamination or decommissioning activity or license termination for the ISFSI.
The proposed action provides a means for PGE to demonstrate that it will have sufficient funding to cover the costs of decommissioning the ISFSI, including the reduction of the residual radioactivity at the ISFSI to the level specified by the applicable NRC's license termination regulations concerning release of the property (10 CFR 20.1402 or 10 CFR 20.1403).
The NRC's approval of the DFP will not change the scope or nature of the operation of the ISFSI and will not authorize any changes to licensed operations or maintenance activities. The NRC's approval of the DFP will not result in any changes in the types, characteristics, or quantities of radiological or non-radiological effluents released into the environment from the ISFSI, or result in the creation of any solid waste. Moreover, the approval of the DFP will not authorize any construction activity or facility modification. Therefore, the NRC staff concludes that the approval of the DFP is a procedural and administrative action that will not result in any significant impact to the environment.
Section 106 of the National Historic Preservation Act of 1966, as amended (NHPA), requires Federal agencies to consider the effects of their undertakings on historic properties. In accordance with the NHPA implementing regulations at 36 CFR part 800, “Protection of Historic Properties,” the NRC's approval of PGE's DFP constitutes a Federal undertaking. The NRC, however, has determined that the approval of the DFP is a type of undertaking that does not have the potential to cause effects on historic properties, assuming such historic properties were present, because the NRC's approval of PGE's DFP will not authorize or result in changes to licensed operations or maintenance activities, or changes in the types, characteristics, or quantities of radiological or non-radiological effluents released into the environment from the ISFSI, or result in the creation of any solid waste. Therefore, in accordance with 36 CFR 800.3(a)(1), no consultation is required under Section 106 of the NHPA.
Under Section 7 of the Endangered Species Act of 1973, prior to taking a proposed action, a Federal agency must determine whether (i) endangered and threatened species or their critical habitats are known to be in the vicinity of the proposed action and if so, whether (ii) the proposed Federal action may affect listed species or critical habitats. If the proposed action may affect listed species or critical habitats, the federal agency is required to consult with the U.S. Fish and Wildlife Service (FWS) and/or the U.S. National Marine Fisheries Service. In accordance with 50 CFR 402.13, the NRC has engaged in informal consultation with the FWS. The NRC has determined that the proposed action is not likely to adversely affect listed species or their critical habitats because the NRC's approval of PGE's DFP will not authorize or result in changes to licensed operations or maintenance activities, or changes in the types, characteristics, or quantities of radiological or non-radiological effluents released into the environment from the ISFSI, or result in the creation of any solid waste. The FWS has concurred with the NRC's determination that the proposed action is not likely to adversely affect listed species or critical habitat.
In addition to the proposed action, the NRC evaluated the no-action alternative. The no-action alternative is to deny PGE's DFP. A denial of a DFP that meets the criteria of 10 CFR 72.30(b) does not support the regulatory intent of the 2011 rulemaking. As noted in the rulemaking EA (ADAMS Accession No. ML090500648), not promulgating the 2011 final rule would have increased the likelihood of additional legacy sites. Thus, denying the licensee's DFP, which the NRC has found to meet the criteria of 10 CFR 72.30(b), will undermine the licensee's decommissioning planning. On this basis, the NRC has concluded that the no-action alternative is not a viable alternative.
The NRC staff consulted with other agencies and parties regarding the environmental impacts of the proposed action. The NRC provided a draft of its EA to the State of Oregon's Department of Nuclear Energy on June 24, 2015. The State responded via email on June 29, 2015, stating that it had no comments on the proposed action. The NRC also consulted with the FWS. The FWS concurred with the NRC's determination that the proposed action is not likely to adversely affect listed species or critical habitat.
The NRC staff has determined that the proposed action, the review and approval of the DFP, submitted in accordance with 10 CFR 72.30(b), will not authorize or result in changes to licensed operations or maintenance activities, or changes in the types, characteristics, or quantities of radiological or non-radiological effluents released into the environment from the ISFSI, or result in the creation of any solid waste. Moreover, the approval of the DFP will not authorize any construction activity, facility modification, or any other land-disturbing activity. The NRC staff has concluded that the proposed action is a procedural and administrative action and as such, that the proposed action will not have a significant effect on the quality of the human environment. Therefore, the NRC staff has determined not to prepare an EIS for the proposed action but will issue this FONSI. In accordance with 10 CFR 51.32(a)(4), the FONSI incorporates the EA by reference.
The following documents, related to this document, can be found using any of the methods provided in the following table. Instructions for accessing ADAMS were provided under the
For the Nuclear Regulatory Commission.
U.S. Nuclear Regulatory Commission.
Notice of meeting.
The U.S. Nuclear Regulatory Commission will convene a teleconference meeting of the Advisory Committee on the Medical Uses of Isotopes (ACMUI) on March 10, 2016, to discuss the draft report of the ACMUI Training and Experience for Authorized Users of Alpha, Beta and Gamma Emitters (Title 10 of the
The teleconference meeting will be held on Thursday, March 10, 2016, 1:30 p.m. to 3:30 p.m. Eastern Time.
Dr. Philip Alderson, ACMUI Chairman, will preside over the meeting. Dr. Alderson will conduct the meeting in a manner that will facilitate the orderly conduct of business. The following procedures apply to public participation in the meeting:
1. Persons who wish to provide a written statement should submit an electronic copy to Ms. Holiday at the contact information listed above. All submittals must be received by March 07, 2016, three business days prior to the meeting, and must pertain to the topic on the agenda for the meeting.
2. Questions and comments from members of the public will be permitted during the meetings, at the discretion of the Chairman.
3. The draft transcript and meeting summary will be available on ACMUI's Web site
This meeting will be held in accordance with the Atomic Energy Act of 1954, as amended (primarily Section 161a); the Federal Advisory Committee Act (5 U.S.C. App); and the Commission's regulations in 10 CFR part 7.
Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Form F-8 (17 CFR 239.38) may be used to register securities of certain Canadian issuers under the Securities Act of 1933 (15 U.S.C. 77a
Written comments are invited on: (a) whether this proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) the accuracy of the agency's estimate of the burden imposed by the collection of information; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted in writing within 60 days of this publication.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid control number.
Please direct your written comment to Pamela Dyson, Director/Chief Information Officer, Securities and Exchange Commission, c/o Remi Pavlik-Simon, 100 F Street NE., Washington, DC 20549 or send an email to:
Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (“PRA”) (44 U.S.C. 3501
Form BD is the application form used by firms to apply to the Commission for registration as a broker-dealer, as required by Rule 15b1-1. Form BD also is used by firms other than banks and registered broker-dealers to apply to the Commission for registration as a municipal securities dealer or a government securities broker-dealer. In addition, Form BD is used to change information contained in a previous Form BD filing that becomes inaccurate.
The total industry-wide annual time burden imposed by Form BD is approximately 4,999 hours, based on approximately 13,732 responses (193 initial filings + 13,539 amendments). Each application filed on Form BD requires approximately 2.75 hours to complete and each amended Form BD requires approximately 20 minutes to complete. (193 × 2.75 hours = 531 hours; 13,539 × 0.33 hours = 4,468 hours; 531 hours + 4,468 hours = 4,999 hours.) The staff believes that a broker-dealer would have a Compliance Manager complete and file both applications and amendments on Form BD at a cost of $279/hour. Consequently, the staff estimates that the total internal cost of compliance associated with the annual time burden is approximately $1,394,721 per year ($279 × 4999). There is no external cost burden associated with Rule 15b1-1 and Form BD.
The Commission uses the information disclosed by applicants in Form BD: (1) To determine whether the applicant meets the standards for registration set forth in the provisions of the Exchange Act; (2) to develop a central information resource where members of the public may obtain relevant, up-to-date information about broker-dealers, municipal securities dealers, and government securities broker-dealers, and where the Commission, other regulators, and SROs may obtain information for investigatory purposes in connection with securities litigation; and (3) to develop statistical information about broker-dealers, municipal securities dealers, and government securities broker-dealers. Without the information disclosed in Form BD, the Commission could not effectively implement policy objectives of the Exchange Act with respect to its investor protection function.
Written comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted in writing within 60 days of this publication.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information under the PRA unless it displays a currently valid OMB control number.
Please direct your written comments to: Pamela Dyson, Director/Chief Information Officer, Securities and Exchange Commission, c/o Remi Pavlik-Simon, 100 F Street NE., Washington, DC 20549, or send an email to:
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange filed a proposal to authorize the Exchange's equity options platform (“EDGX Options”) to make a modification to Rule 21.1 (Definitions) in connection with the operation of the attribution feature of EDGX Options, as described below. The Exchange has designated this proposal as non-controversial and provided the Commission with the notice required by Rule 19b-4(f)(6)(iii) under the Act.
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
The Exchange is proposing to modify Rule 21.1, Definitions, which sets forth the various definitions applicable to the operation of the EDGX Options platform, including order types and order type modifiers accepted by EDGX Options. As set forth in Rule 21.1, an order can be attributed on EDGX Options, meaning that such order is displayed with not only a price and size
While the Exchange does not propose to modify the identification of Customer interest, orders or trades to either OPRA or on Exchange proprietary data feeds, the Exchange proposes to eliminate the ability for a Customer order to also be an Attributable Order. In other words, though Customer interest, orders and trades would still be identified as such through applicable data feeds, only non-Customer orders could be identified on Exchange data feeds with attribution to a specified MPID. The Exchange believes that limiting the use of Attributable Orders to non-Customer orders is reasonable because such functionality was primarily intended for Market Makers and other professional participants that typically provide liquidity to indicate their presence on EDGX Options with attribution to their MPID.
The Exchange notes that it does not propose the change set forth above due to concerns with respect to Customer orders being entered as Attributable Orders but rather due to current system limitations in supporting both the attribution feature and the identifcation [sic] of Customer orders as such. On balance, the Exchange believes that the identification of orders as Customer orders is more consistent with the operation of other options exchanges and important to the Exchange's pro rata priority model than is the attribution of a particular Customer order to a specific MPID.
The Exchange also notes that the equities platform of the Nasdaq Stock Market LLC (“Nasdaq”) also limits the availability of attribution to certain market participants, including market makers.
The Exchange believes that its proposal is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6(b) of the Act.
The proposed rule change will allow the Exchange to continue to accept Attributable Orders from non-Customers while also designating Customer orders as such on applicable data feeds. As set forth above, the Exchange believes that non-Customers quoting and providing liquidity are the most likely users of the Attributable Order feature and that restricting Customer orders from the use of the feature is appropriate given the separate identification of Customer orders on applicable data feeds. As set forth above, at least one other exchange has similarly limited attribution to certain professional market participants.
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 designed to address any competitive issues but rather to make a modification to the Exchange's attribution offering to ensure that the Exchange's System and rules are consistent and that the most important features can be offered to Users in their varying capacities. As noted above, at least one other exchange has similarly limited attribution to certain professional market participants.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from members or other interested parties.
The Exchange has filed the proposed rule change 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 filing. However, Rule 19b-4(f)(6)(iii) permits the Commission to designate a shorter time if such action is consistent with the protection of investors and the public interest. The Exchange has asked the Commission to waive the 30-day operative delay so that the Exchange may continue to permit non-Customers to attribute their orders and to allow the Exchange to label orders as Customer Orders. The Commission believes that the proposal will update the rules of the Exchange to accurately reflect how the System operates with respect to Attributable Orders thereby avoiding confusion by market participants. Based on the foregoing, the Commission believes that waiving the 30-day operative delay is consistent with the protection of investors and the public interest.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Notice is hereby given that pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The collection of information obligations of Rule 605 apply to all market centers that receive covered orders in national market system securities. The Commission estimates that approximately 132 market centers are subject to the collection of information obligations of Rule 605. Each of these respondents is required to respond to the collection of information on a monthly basis.
The Commission staff estimates that, on average, Rule 605 causes respondents to spend 6 hours per month to collect the data necessary to generate the reports, or 72 hours per year. With an estimated 132 market centers subject to Rule 605, the total data collection time burden to comply with the monthly reporting requirement is estimated to be 9,504 hours per year.
Based on discussions with industry sources, the Commission staff estimates that an individual market center could retain a service provider to prepare a monthly report using the data collected for approximately $2,978 per month. This per-respondent estimate is based on the rate that a market center could expect to obtain if it negotiated on an individual basis. Based on the $2,978 estimate, the monthly cost to the 132 market centers to retain service providers to prepare reports would be $393,096, or an annual cost of approximately $4,717,152.
Written comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information will have practical utility; (b) the accuracy of the Commission's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted in writing within 60 days of this publication.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information under the PRA unless it displays a currently valid OMB control number.
Please direct your written comments to Pamela C. Dyson, Director/Chief
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
FINRA is proposing to extend the implementation date of the No-Remuneration indicator to July 18, 2016. The proposed rule change would not make any changes to FINRA rules.
The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
On July 20, 2015, FINRA filed a proposed rule change to amend FINRA Rule 6730 (Transaction Reporting), which governs the reporting of eligible transactions to its Trade Reporting and Compliance Engine (“TRACE”).
In SR-FINRA-2015-026, FINRA proposed to amend Rule 6730 to require that firms use a “No-Remuneration” indicator to identify those transactions for which a commission or mark-up/mark-down is not reflected in a TRACE trade report. The Commission approved the proposal, on October 16, 2015.
FINRA has filed the proposed rule change for immediate effectiveness.
FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA believes that the extension of the implementation date until July 18, 2016, is consistent with the Act in that it would provide members with additional time to complete the systems changes necessary to comply with SR-FINRA-2015-026.
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.
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) of the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to the provisions of Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange is filing a proposal to amend Exchange Rule 301, Just and Equitable Principles of Trade, to add Interpretations and Policies .03 to Rule 301 to state in the Exchange's rules that the practice of unbundling an order is considered conduct inconsistent with just and equitable principles of trade.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to amend Exchange Rule 301, Just and Equitable Principles of Trade, to add Interpretations and Policies .03 to Rule 301 that states that the practice of unbundling an order is considered conduct inconsistent with just and equitable principles of trade. The proposal codifies existing Exchange procedures when dealing with the unlawful bundling of orders.
The purpose of the proposed rule change is to amend Exchange Rule 301 by adding a new Interpretations and Policies .03 to Rule 301 which will expressly prohibit the splitting-up of an order into smaller orders; a practice also known as unbundling, or trade shredding. More specifically, the Exchange is proposing to add language to its existing rules to prohibit Members
Unbundling, or trade shredding, is the practice of breaking up an order into multiple smaller orders for some purpose other than best execution of the order. The practice of unbundling has in the past been used for such purposes as improperly maximizing commissions and fees charged to customers, distorting trade data, or circumventing rules pertaining to maximum order size. In addition, the unbundling of a large order into several smaller orders could be done so as to affect the allocation of a trade among market participants pursuant to the allocation methodology
Pursuant to Exchange Rule 301, Members must observe high standards of commercial honor and just and equitable principles of trade. The Exchange would consider a Member to have engaged in conduct inconsistent with just and equitable principles of trade were they to unbundle an order which (1) distorts fees and/or commissions to the detriment of a customer or the Exchange, (2) causes an unnecessary delay in the execution of an order, or (3) circumvents an Exchange rule or federal securities law, including those rules pertaining to order size and trade allocation. Members engaging in conduct inconsistent with just and equitable principles of trade are subject to formal disciplinary action by the Exchange.
The Exchange now proposes to adopt Interpretations and Policies .03 to Rule 301, which will expressly state that the Exchange considers it to be conduct inconsistent with just and equitable principles of trade for a Member to split an order into multiple smaller orders for any purpose other than seeking the best execution of the entire order.
The Exchange believes that, by adopting this proposed language which serves to codify existing Exchange procedures when dealing with the unlawful unbundling of orders, it will deter and help to prevent this distortive practice, and therefore promote just and equitable principles of trade.
The Exchange notes that it considers unbundling, among other things, to be conduct inconsistent with just and equitable principles of trade in the rules governing its price improvement mechanism, MIAX PRIME.
MIAX believes that its proposed rule change is consistent with Section 6(b) of the Act
The proposed rule change is designed to protect investors and the public interest and to promote just and equitable principles of trade by preventing the distortive practice of unbundling, or trade shredding, which conduct is considered inconsistent with the just and equitable principles of trade.
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. Specifically, the Exchange believes the proposed changes will not impose any burden on intra-market competition because it applies to all MIAX participants equally. In addition, the Exchange does not believe the proposal will impose any burden on inter-market competition as the proposal is intended to protect investors by preventing the distortive practice of unbundling, or trade shredding.
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 after the date of the filing, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed pursuant to Rule 19b-4(f)(6) under the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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 filed a proposal to extend the pilot period for the Exchange's Supplemental Competitive Liquidity Provider Program (the “Program”), which is currently set to expire on January 28, 2016, for three months, to expire on April 28, 2016. The Exchange has designated this proposal as non-controversial and provided the Commission with the notice required by Rule 19b-4(f)(6)(iii) under the Act.
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
On August 30, 2011, the Exchange received approval of rules applicable to the qualification, listing and delisting of securities of issuers on the Exchange.
The Program was approved by the Commission on a pilot basis running one-year from the date of implementation.
The Exchange established the Program in order to enhance liquidity on the Exchange in certain ETPs listed on the Exchange (and thereby enhance the Exchange's ability to compete as a listing venue) by providing a mechanism by which ETP CLPs compete for part of a daily quoting incentive on the basis of providing the most aggressive quotes with the greatest amount of size. Such competition has the ability to reduce spreads, facilitate the price discovery process, and reduce costs for investors trading in such securities, thereby promoting capital formation and helping the Exchange to compete as a listing venue. The Exchange believes that extending the pilot is appropriate because the Exchange is also planning to submit a proposal to make the Program permanent. As part of this proposal, the Exchange is also preparing a report analyzing the Program. As such, the Exchange believes that it is appropriate to extend the current operation of the Program for three months in order to provide enough time for the Program to continue operating while such proposal is under consideration by the Commission. Through this filing, the Exchange seeks to extend the current pilot period of the Program until April 28, 2016.
The Exchange believes that its proposal is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6(b) of the Act.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed rule change extends an established pilot program for 6 [sic] months, thus allowing the Program to enhance competition in both the listings market and in competition for market makers. The Program will continue to promote competition in the listings market by providing issuers with a vehicle for paying the Exchange additional fees in exchange for incentivizing tighter spreads and deeper liquidity in listed securities and allow the Exchange to continue to compete with similar programs at Nasdaq Stock Market LLC
The Exchange also believes that extending the pilot program for an additional 6 [sic] months will allow the Program to continue to enhance competition among market participants by creating incentives for market makers to compete to make better quality markets. By continuing to require that market makers both meet the quoting requirements and also compete for the daily financial incentives, the quality of quotes on the Exchange will continue to improve. This, in turn, will attract more liquidity to the Exchange and further improve the quality of trading in exchange-listed securities participating in the Program, which will also act to bolster the Exchange's listing business.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from Members or other interested parties.
Because the 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
A proposed rule change filed under Rule 19b-4(f)(6) normally does not become operative before 30 days from the date of the filing. However, pursuant to Rule 19b-4(f)(6)(iii),
The Exchange has asked the Commission to waive the 30-day operative delay. The Commission believes that waiving the 30-day operative delay is consistent with the protection of investors and the public interest. Waiver of the operative delay will allow the Exchange to extend the Program prior to its expiration on January 28, 2016, which will ensure that the Program continues to operate uninterrupted while the Exchange and the Commission continue to analyze data regarding the Program. Therefore, the Commission hereby waives the 30-day operative delay and designates the proposed rule change to be operative upon filing with the Commission.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposal is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to make adjustments to its Options Regulatory Fee (“ORF”) by amending Section IV, Part D of the Pricing Schedule.
While changes to the Pricing Schedule pursuant to this proposal are effective upon filing, the Exchange has designated these changes to be operative on February 1, 2016.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to decrease the ORF from $0.0035 to $0.0034 as of February 1, 2016 to account for additional fine revenue, cost reductions and to balance the Exchange's regulatory revenue against the anticipated costs and potential fines.
The ORF is assessed to each member for all options transactions executed or cleared by the member that are cleared at The Options Clearing Corporation (“OCC”) in the Customer range (
The ORF is designed to recover a portion of the costs to the Exchange of the supervision and regulation of its members, including performing routine surveillances, investigations, examinations, financial monitoring, and policy, rulemaking, interpretive, and enforcement activities. The Exchange believes that revenue generated from the ORF, when combined with all of the Exchange's other regulatory fees, will cover a material portion, but not all, of the Exchange's regulatory costs. The Exchange will continue to monitor the amount of revenue collected from the ORF to ensure that it, in combination with its other regulatory fees and fines, does not exceed regulatory costs. If the Exchange determines regulatory revenues exceed regulatory costs, the Exchange will adjust the ORF by submitting a fee change filing to the Commission.
The Exchange is proposing to decrease the ORF from $0.0035 to $0.0034 as of February 1, 2016 in order to account for regulatory revenue from disciplinary actions taken by the Exchange. The Exchange regularly reviews its ORF to ensure that the ORF, in combination with its other regulatory fees and fines, does not exceed regulatory costs. The Exchange believes this adjustment will permit the Exchange to cover a material portion of its regulatory costs, while not exceeding regulatory costs.
The Exchange notified members of this ORF adjustment thirty (30) calendar days prior to the proposed operative date.
The Exchange believes that its proposal is consistent with Section 6(b) of the Act
The Exchange believes that lowering the ORF from $0.0035 to $0.0034 as of February 1, 2016 is reasonable because the Exchange's collection of ORF needs to be balanced against the amount of regulatory revenue collected by the Exchange. The Exchange believes that the proposed adjustments noted herein will serve to balance the Exchange's regulatory revenue against the anticipated regulatory costs. It is further reasonable because this adjustment results in a price reduction.
The Exchange believes that lowering the ORF from $0.0035 to $0.0034 as of February 1, 2016 is equitable and not unfairly discriminatory because this adjustment would be applicable to all members on all of their transactions that clear as Customer at OCC. In addition, the ORF seeks to recover the costs of supervising and regulating members, including performing routine surveillances, investigations, examinations, financial monitoring, and policy, rulemaking, interpretive, and enforcement activities.
The ORF is not charged for member proprietary options transactions because members incur the costs of owning memberships and through their memberships are charged transaction fees, dues and other fees that are not applicable to non-members. Moreover, the Exchange believes the ORF ensures fairness by assessing higher fees to those members that require more Exchange regulatory services based on the amount of Customer options business they conduct.
Regulating Customer trading activity is more labor intensive and requires greater expenditure of human and technical resources than regulating non-Customer trading activity. Surveillance, regulation and examination of non-Customer trading activity generally tends to be more automated and less labor intensive. As a result, the costs associated with administering the Customer component of the Exchange's overall regulatory program are anticipated to be higher than the costs associated with administering the non-Customer component of its regulatory program. The Exchange proposes assessing higher fees to those members that will require more Exchange regulatory services based on the amount of Customer options business they conduct.
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.
The Exchange does not believe that reducing its ORF creates an undue burden on intra-market competition because the adjustment will apply to all members on all of their transactions that clear as Customer at OCC. The Exchange is obligated to ensure that the amount of regulatory revenue collected from the ORF, in combination with its other regulatory fees and fines, does not exceed regulatory costs. Additionally, the dues and fees paid by members go into the general funds of the Exchange,
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 Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Notice is hereby given, pursuant to the provisions of the Government in the Sunshine Act, Public Law 94-409, that the Securities and Exchange Commission will hold an Open Meeting on Wednesday, February 10, 2016 at 10:00 a.m., in the Auditorium, RoomL-002.
The subject matter of the Open Meeting will be:
• The Commission will consider whether to adopt rules under the Securities Exchange Act of 1934 providing for the application of the Title VII security-based swap dealer
At times, changes in Commission priorities require alterations in the scheduling of meeting items.
For further information and to ascertain what, if any, matters have been added, deleted, or postponed, please contact:
The Office of the Secretary at (202) 551-5400.
Pursuant to the provisions of Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange is filing a proposal to amend Exchange Rules 503, Openings on the Exchange, and 515, Execution of Orders and Quotes.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The purpose of the proposal is to adopt new rule text and provide additional clarity to MIAX participants regarding the manner in which non-routable, or Do Not Route (“DNR”),
First, the Exchange proposes to amend Rule 503(f), Opening Process, to clarify the process that occurs when (i) the MIAX System
Additionally, the Exchange proposes to amend current Exchange Rule 515(c)(1)(ii) to explicitly state that, when the MIAX System opens without an opening transaction, and instead opens by disseminating the Exchange's best bid and offer among quotes and orders that exist in the System at that time as described in Rule 503(f)(1), non-routable orders then in the System that cross the ABBO will be cancelled and are not included in the Managed Interest Process described below.
Exchange Rule 503(f) describes the Opening Process on the Exchange, in which the System goes through a number of processes seeking an opening price at which the greatest number of contracts will trade. The Opening Process also includes the routing of orders to away markets in situations where the Exchange cannot execute all contracts at its opening price.
If, however, there is no opening transaction and instead the Exchange opens by disseminating the Exchange's best bid and offer among quotes and orders that exist in the System at that time,
Currently, the System executes orders at the opening that have contingencies, including non-routable orders (DNR Orders) to the extent possible. Non-routable orders are handled after the opening in accordance with Rule 515.
The proposed amendment to Exchange Rule 515(c)(1)(ii) is intended to codify existing functionality concerning the Exchange's Managed Interest Process. The Managed Interest Process is a process for non-routable orders during which, if the limit price locks or crosses the current opposite side National Best Bid or Offer (“NBBO”), the System will display the order one Minimum Price Variation (“MPV”) away from the current opposite side NBBO, and book the order at an undisplayed price that locks the current opposite side NBBO. Should the NBBO price change to an inferior price level, the order's undisplayed price will re-price to lock the new NBBO and the managed order's displayed price will continue to re-price one MPV away from the new NBBO until (i) the order has traded to and including its limit price, (ii) the order has traded to and including its price protection limit at which any remaining contracts are cancelled, (iii) the order is fully executed or (iv) the order is cancelled.
The proposed rule change to Exchange Rule 503 concerning the Opening Process is related to the Managed Interest Process in Exchange Rule 515 because non-routable orders that are not executed at the opening under certain circumstances are not included in the Managed Interest Process and are instead cancelled by the System. Specifically, the proposed rule change to Exchange Rule 503(f)(1) is intended to clarify that, when the Exchange opens by disseminating quotations rather than executing contracts after the Opening Process, non-routable orders then in the System that cross the ABBO will be cancelled and are not included in the Managed Interest Process, as described in Rule 515(c)(1)(ii)(B).
Proposed Rule 503(f)(2)(vii)(B)5 [sic] would add language to existing rule text to state clearly in the Exchange's rules that the rule applies when there is an opening transaction. Specifically, if there is an opening transaction, any unexecuted contracts from the imbalance not traded or routed will be cancelled back to the entering Member if the price for those contracts crosses the opening price, unless the Member that submitted the original order has instructed the Exchange in writing to re-enter the remaining size, in which case
Consistent with the proposed change to Exchange Rule 503(f)(1), proposed Rule 515(c)(1)(ii)(B) would state specifically that, when the System opens without an opening transaction, and instead opens by disseminating the Exchange's best bid and offer among quotes and orders that exist in the System at that time as described in Rule 503(f)(1), non-routable orders then in the System that cross the ABBO will be cancelled and are not included in the Managed Interest Process. This proposed amendment addresses any perceived discrepancy between the rule text description of how this process works and how it is actually working in production, and provides consistency in the Exchange's rules concerning the Opening Process and how that relates to the Managed Interest Process.
The Exchange believes that the codification of the cancellation of non-routable orders that cross the ABBO when the System opens without an opening transaction and instead opens by disseminating the Exchange's best bid and offer among quotes and orders that exist in the System at that time, reflects the Exchange's intention to further protect investors that elect to submit non-routable orders. This existing functionality is intended to enable participants that submit non-routable orders that have been handled during the opening but not executed to make informed decisions about such orders based upon transparent market conditions (
MIAX believes that its proposed rule change is consistent with Section 6(b) of the Act
The existing functionality concerning the Opening Process and the description of the circumstances where non-routable orders that are handled during the Opening Process are not included in the Managed Interest Process because they are cancelled. This functionality and proposed codification of it as described herein removes impediments to and perfects the mechanisms of a free and open market and a national market system and, in general, protects investors and the public interest, by giving participants that submit non-routable orders that are not executed at the opening an opportunity to make decisions concerning their orders based upon then-current market conditions, which were unknown at the time they submitted their orders. Routable orders that cross away markets are sent to such away markets for execution when the Exchange cannot execute at the opening; non-routable orders that cross away markets are not. Absent an execution, the Exchange believes that participants that submitted non-routable orders that are handled but not executed during the opening process should have the opportunity to make further decisions regarding such orders based upon current market conditions, and thus the System cancels such orders and reports this to the affected participants. This benefits not only MIAX participants but benefits the marketplace as a whole.
The inclusion of the functionality of the System in the rules promotes transparency and clarity in the Exchange's rules. The transparency and accuracy resulting from the codification of this functionality is consistent with the Act because it removes impediments to and perfects the mechanism of a free and open market and a national market system, and, in general, protects investors and the public interest, by accurately describing the steps taken by the System in the limited scenario when the Exchange opens by disseminating quotations rather than executing contracts after the Opening Process, and non-routable orders cross the NBBO.
MIAX participants should have a better understanding of the Exchange's Managed Interest Process in this limited circumstance. The codification and clarification of the System's functionality is designed to promote just and equitable principles of trade by providing a clear and objective description to all participants of how opening non-routable orders will be handled, and should assist investors in making decisions concerning their non-routable orders.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. Specifically, the Exchange believes the proposed changes will not impose any burden on intra-market competition because it applies to all MIAX participants equally. In addition, the Exchange does not believe the proposal will impose any burden on inter-market competition as the proposal is intended to protect investors by providing further transparency regarding the Exchange's Managed Interest Process in the limited scenario described above.
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 after the date of the filing, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed pursuant to Rule 19b-4(f)(6) under the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Form F-7 (17 CFR 239.37) is a registration statement under the Securities Act of 1933 (15 U.S.C. 77a
Written comments are invited on: (a) Whether this proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) the accuracy of the agency's estimate of the burden imposed by the collection of information; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted in writing within 60 days of this publication.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid control number.
Please direct your written comment to Pamela Dyson, Director/Chief Information Officer, Securities and Exchange Commission, c/o Remi Pavlik-Simon, 100 F Street NE., Washington, DC 20549 or send an email to:
Pursuant to Section 19(b)(1)
The Exchange proposes to amend certain of its rules related to Binary Return Derivatives contracts. 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 is proposing to amend certain of its rules related to Binary Return Derivatives contracts (“ByRDs”), which the Exchange introduced in 2007.
First, the Exchange proposes to add Rule 953ByRDs to make clear that the Exchange would halt or suspend trading for a ByRDs contract to the same extent that it halts or suspends trading under Rule 953NY in an option contract on the same underlying security.
Next, the Exchange proposes to modify Rule 903ByRDs(b) (Series of ByRDs Open for Trading), which currently provides that “[n]ew expiration week series will be added for trading on Thursday each week, unless Friday is an Exchange holiday in which case new expiration series would be added for trading on Wednesday.”
The Exchange also proposes to amend Rule 975NY (Nullification and Adjustment of Options Transactions including Obvious Errors) regarding the treatment of ByRDs in the event of a catastrophic error. Current Rule 975NY(d)(3)(A) provides that “[u]pon proper notification as described in section (d)(2) of this Rule, any transaction in ByRDs, qualifying as a Catastrophic Error will automatically be adjusted by the Exchange to $1.02 per contract unless both parties mutually agree to nullify the transaction or both parties mutually agree to a different adjustment price. However, the Exchange proposes to modify this rule to clarify that any transactions in ByRDs qualifying as a Catastrophic Error “that is higher or lower than the Theoretical Price by $.50 or more shall be deemed a Catastrophic Error, subject to the adjustment procedures of paragraph (d)(3) unless such adjustment would result in a price higher than $1.02, in which case the adjustment price shall be $1.02.”
Finally, the Exchange proposes to delete extraneous text from Rule 462(d)(10)(A), regarding margin accounts, such that the revised text would provide that “[e]xcept as provided below, no ByRDs option carried long in a customer's account shall be considered of any value for the purpose of computing the margin required in the account of such customer.”
The Exchange proposes to announce the implementation of the proposed rule change via Trader Update.
The Exchange believes the proposed rule change is consistent with Section 6(b)
Specifically, the proposed change to Rule 903ByRDs(b) to cover instances when an Exchange holiday falls on a Thursday would allow the Exchange to add new series during Thanksgiving week or anytime Christmas or New Year's falls on a Thursday, which increased flexibility would remove impediments to, and perfect the mechanism of, a free and open market and a national market system to the benefit of market participants.
In addition, the Exchange believes that the proposed rule to make clear that ByRDs would be treated the same as other options contracts, in the event of a trading halt or suspension, would remove impediments to, and perfect the mechanisms of, a free and open market because it would add clarity and transparency to Exchange rules. Moreover, this proposed change would ensure consistent treatment of ByRDs contracts in the event of a halt or suspension of trading in options contracts on the same underlying security.
The proposed change to Rule 975NY(d)(3)(A), regarding the treatment ByRDs transactions deemed Catastrophic Errors is designed to promote just and equitable principles of trade, and to remove impediments to and perfect the mechanism of a free and open market and a national market system, as the proposed change would ensure that ByRDs trades that are deemed Catastrophic Errors are appropriately adjusted.
Finally, the proposed change to remove incorrect and extraneous rule text from Rule 462(d)(10)(A) adds clarity and transparency to Exchange rules and reduces potential investor confusion, which would remove impediments to and perfect the mechanism of a free and open market and a national market system.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed change is not designed to address any competitive issue but rather to add clarity and transparency to Exchange rules, thereby reducing confusion and making the Exchange's rules easier to understand and navigate. The Exchange believes that the proposed rule change will serve to promote regulatory clarity and consistency, thereby reducing burdens on the marketplace and facilitating investor protection.
No written comments were solicited or received with respect to the proposed rule change.
Because the proposed rule change does not (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission 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.
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 of OMB-approved information collections.
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. (OMB) Office of Management and Budget, Attn: Desk Officer for SSA, Fax: 202-395-6974, Email address:
(SSA) Social Security Administration, OLCA, Attn: Reports Clearance Director, 3100 West High Rise, 6401 Security Blvd., Baltimore, MD 21235, Fax: 410-966-2830, Email address:
Or you may submit your comments online through
I. The information collections below are pending at SSA. SSA will submit them 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 April 8, 2016. Individuals can obtain copies of the collection instruments by writing to the above email address.
1. Statement for Determining Continuing Eligibility, Supplemental Security Income Payment(s)—20 CFR 416.204—0960-0416. SSA conducts disability redeterminatons to determine if Supplemental Security Income (SSI) recipients (1) met and continue to meet all statutory and regulatory requirements for SSI eligibility and (2) are receiving the correct SSI payment amount. SSA makes these redeterminations through periodic use of Form SSA-8203BK. SSA conducts this legally mandated information collection in field offices via personal contact (face-to-face or telephone interview) using the automated Modernized SSI Claim System (MSSICS). The respondents are SSI recipients or their representative payees.
Type of Request: Revision of an OMB-approved information collection.
2. Information About Joint Checking/Savings Account—20 CFR 416.1201 and 416.1208—0960-0461. SSA considers a person's resources when evaluating eligibility for SSI. Generally, we consider funds in checking and savings accounts as resources owned by the individuals whose names appear on the account. However, individuals applying for SSI may rebut this assumption of ownership in a joint account by submitting certain evidence to establish the funds do not belong to them. SSA uses Form SSA-2574 to collect information from SSI applicants and recipients who object to the assumption that they own all or part of the funds in a joint checking or savings account bearing their names. SSA collects information about the account from both the SSI applicant or recipient and the other account holder(s). After receiving the completed form, SSA determines if we should consider the account to be a resource for the SSI applicant and recipient. The respondents are applicants and recipients of SSI, and individuals who list themselves as joint owners of financial accounts with SSI applicants or recipients.
Type of Request: Revision of an OMB-approved information collection.
3. Plan for Achieving Self-Support (PASS)—20 CFR 416.110(e), 416.1180-416.1182, 416.1225-416.1227—0960-0559. The SSI program encourages recipients to return to work. One of the program objectives is to provide incentives and opportunities that help recipients toward employment. The PASS provision allows individuals to use available income or resources (such as business equipment, education, or specialized training) to enter or re-enter the workforce and become self-supporting. In turn, SSA does not count the income or resources recipients use to fund a PASS when determining an individual's SSI eligibility or payment amount. An SSI recipient who wants to use available income and resources to obtain education or training to become self-supporting completes Form SSA-545. SSA uses the information from the SSA-545 to evaluate the recipient's PASS, and to determine eligibility under the provisions of the SSI program. The respondents are SSI recipients who want to develop a return-to-work plan.
Type of Request: Revision of an OMB-approved information collection.
4. Registration for Appointed Representative Services and Direct Payment—0960-0732. SSA uses Form SSA-1699 to register appointed representatives of claimants before SSA who:
• Want to register for direct payment of fees;
• Registered for direct payment of fees prior to 10/31/09, but need to update their information;
• Registered as appointed representatives on or after 10/31/09, but need to update their information; or
• Received a notice from SSA instructing them to complete this form.
By registering these individuals, SSA: (1) Authenticates and authorizes them to do business with us; (2) allows them to access our records for the claimants they represent; (3) facilitates direct payment of authorized fees to appointed representatives; and, (4) collects the information we need to meet Internal Revenue Service (IRS) requirements to issue specific IRS forms if we pay an appointed representative in excess of a specific amount ($600). The respondents are appointed representatives who want to use Form SSA-1699 for any of the purposes cited in this Notice.
Type of Request: Revision of an OMB-approved information collection.
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 March 9, 2016. Individuals can obtain copies of the OMB clearance packages by writing to
1. Certificate of Responsibility for Welfare and Care of Child Not in Applicant's Custody—20 CFR 404.330, 404.339-404.341 and 404.348-404.349—0960-0019. Under the provisions of the Social Security Act (Act), non-custodial parents who are filing for spouse, mother, or father Social Security benefits based on having the child of a number holder or worker in their care, must meet the in-care requirements the Act discusses. The in-care provision requires claimants to have an entitled child under age 16 or disabled in their care. SSA uses Form SSA-781, Certificate of Responsibility for Welfare and Care of Child in Applicant's Custody, to determine if claimants meet the requirement. The respondents are applicants for spouse, mother's or father's Social Security benefits.
Type of Request: Revision of an OMB-approved information collection.
2. Authorization for the Social Security Administration to Obtain Account Records from a Financial Institution—20 CFR 416.200 and 416.203—0960-0293. SSA collects and verifies financial information from individuals applying for Title II and Title XVI waiver determinations, as well as those who apply for, or currently receive (in the case of redetermination) Supplemental Security Income (SSI) payments. We require the financial information from these applicants to: (1) Determine the eligibility of the applicant or recipient for Supplemental Security Income (SSI) benefits; or (2) determine if a request to waive a Social Security overpayment defeats the purpose of the Social Security Act. If the Title II and Title XVI waiver applicants, or the SSI claimants provide incomplete, unavailable, or seemingly altered records, SSA contacts their financial institutions to verify the existence, ownership, and value of accounts owned. Financial institutions need individuals to sign Form SSA-4641-F4, or work with SSA staff to complete one of SSA's electronic applications, e4641 or the Access to Financial Institutions (AFI) screens, to authorize the individual's financial institution to disclose records to SSA. The respondents are Title II and Title XVI recipients applying for waivers, or SSI applicants, recipients, and their deemors to determine SSI eligibility.
Type of Request: Revision of an OMB-approved information collection.
3. Request for Change in Time/Place of Disability Hearing—20 CFR 404.914(c)(2) and 416.1414(c)(2)—0960-0348. At the request of the claimants or their representative, SSA schedules evidentiary hearings at the reconsideration level for claimants of Title II benefits or Title XVI payments when we deny their claims for disability. When claimants or their representatives find they are unable to attend the scheduled hearing, they complete Form SSA-769 to request a change in time or place of the hearing. SSA uses the information as a basis for granting or denying requests for changes and for rescheduling disability hearings. Respondents are claimants or their representatives who wish to request a change in the time or place of their hearing.
Type of Request: Revision of an OMB-approved information collection.
4. Notice Regarding Substitution of Party Upon Death of Claimant—Reconsideration of Disability Cessation—20 CFR 404.907-404.921 and 416.1407-416.1421—0960-0351. When a claimant dies before we make a determination on that person's request for reconsideration of a disability cessation, SSA seeks a qualified substitute party to pursue the appeal. If SSA locates a qualified substitute party, the agency uses Form SSA-770 to collect information about whether to pursue or withdraw the reconsideration request. We use this information as the basis for the decision to continue or discontinue with the appeals process. Respondents are substitute applicants who are pursuing a reconsideration request for a deceased claimant.
Type of Request: Revision of an OMB-approved information collection.
5. Privacy and Disclosure of Official Records and Information; Availability of Information and Records to the Public—20 CFR 401.40(b)&(c), 401.55(b), 401.100(a), 402.130, 402.185—0960-0566. SSA established methods for the public to: (1) Access their SSA records; (2) allow SSA to disclose records; (3) correct or amend their SSA records; (4) consent to release of their records; (5) request records under the Freedom of Information Act (FOIA); (6) request SSA waive or reduce fees normally charges for release of FOIA; and (7) request access to an extract of their SSN record. SSA often collects the necessary information for these requests through a written letter, with the exception of the consent for release of records, for which we use Form SSA-3288. The respondents are individuals requesting access to, correction of, or disclosure of SSA records.
Type of Request: Revision of an OMB-approved information collection.
6. Beneficiary Interview and Auditor's Observations Form—0960-0630. SSA's Office of the Inspector General collects information from Form SSA-322, the Beneficiary Interview and Auditor's Observation form, to interview beneficiaries or their payees to determine whether they are complying with their duties and responsibilities. The respondents are randomly selected SSI recipients and Social Security beneficiaries who have representative payees.
Type of Request: Revision of an OMB-approved information collection.
7. International Direct Deposit—31 CFR 210—0960-0686. SSA's International Direct Deposit (IDD) Program allows beneficiaries living abroad to receive their payments via direct deposit to an account at a financial institution outside the United States. SSA uses Form SSA-1199-(Country) to enroll Title II beneficiaries residing abroad in IDD, and to obtain the direct deposit information for foreign accounts. Routing account number information varies slightly for each foreign country, so we use a variation of the Treasury Department's Form SF-1199A for each country. The respondents are Social Security beneficiaries residing abroad who want SSA to deposit their Title II benefit payments directly to a foreign financial institution.
Type of Request: Revision of an OMB-approved information collection.
Notice of request for public comment.
The Department of State is seeking Office of Management and Budget (OMB) approval for the information collection described below. In accordance with the Paperwork Reduction Act of 1995, we are requesting comments on this collection from all interested individuals and organizations. The purpose of this notice is to allow 60 days for public comment preceding submission of the collection to OMB.
The Department will accept comments from the public up to April 8, 2016.
You may submit comments by any of the following methods:
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Direct requests for additional information regarding the collection listed in this notice, including requests for copies of the proposed collection instrument and supporting documents, to Keith Miller, Department of State, Office of Overseas Schools, A/OPR/OS, Room H328, SA-1, Washington, DC 20522-0132, who may be reached on 202-261-8200 or at
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We are soliciting public comments to permit the Department to:
• Evaluate whether the proposed information collection is necessary for the proper functions of the Department.
• Evaluate the accuracy of our estimate of the time and cost burden for this proposed collection, including the validity of the methodology and assumptions used.
• Enhance the quality, utility, and clarity of the information to be collected.
• Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.
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 February 29, 2016.
Send comments identified by docket number FAA-2015-0931 using any of the following methods:
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Dan Ngo, 202-267-4264, 800 Independence Avenue SW., Washington, DC 20591.
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 February 29, 2016.
Send comments identified by docket number FAA-2015-0443 using any of the following methods:
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Dan Ngo, 202-267-4264, 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 applications for exemptions; request for comments.
FMCSA announces receipt of applications from 20 individuals for exemption from the vision requirement in the Federal Motor Carrier Safety Regulations. They are unable to meet the vision requirement in one eye for various reasons. The exemptions will enable these individuals to operate commercial motor vehicles (CMVs) in interstate commerce without meeting the prescribed vision requirement in one eye. If granted, the exemptions would enable these individuals to qualify as drivers of commercial motor vehicles (CMVs) in interstate commerce.
Comments must be received on or before March 9, 2016. All comments will be investigated by FMCSA. The exemptions will be issued the day after the comment period closes.
You may submit comments bearing the Federal Docket Management System (FDMS) Docket No. FMCSA-2015-0348 using any of the following methods:
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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 Federal Motor Carrier Safety Regulations for a 2-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.” FMCSA can renew exemptions at the end of each 2-year period. The 20 individuals listed in this notice have each requested such an exemption from the vision requirement in 49 CFR 391.41(b)(10), which applies to drivers of CMVs in interstate commerce. Accordingly, the Agency will evaluate the qualifications of each applicant to determine whether granting an exemption will achieve the required level of safety mandated by statute.
Mr. Barber, 47, has had amblyopia in his left eye since childhood. The visual acuity in his right eye is 20/20, and in his left eye, 20/70. Following an examination in 2015, his ophthalmologist stated, “In my medical
Mr. Barber reported that he has driven straight trucks for 10 years, accumulating 14,000 miles. He holds an operator's license from North Carolina. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Bowman, 50, has had a retinal detachment in his right eye since 2011. The visual acuity in his right eye is no light perception, and in his left eye, 20/20. Following an examination in 2015, his ophthalmologist stated, “In my opinion, Mr. Bowman has sufficient vision to perform driving tasks required for a commercial vehicle.”
Mr. Bowman reported that he has driven straight trucks for 27 years, accumulating 27,000 miles, and tractor-trailer combinations for 25 years, accumulating 750,000 miles. He holds a Class A CDL from Ohio. His driving record for the last 3 years shows one crash, for which he was not cited and to which he did not contribute, and no convictions for moving violations in a CMV.
Mr. Brown, 48, has had amblyopia in his left eye since childhood. The visual acuity in his right eye is 20/20, and in his left eye, 20/60. Following an examination in 2015, his optometrist stated, “Overall, I think that Mr. Brown has very good visual function and life experience, which would allow him to operate a commercial vehicle safely, and efficiently.” Mr. Brown reported that he has driven straight trucks for 13 years, accumulating 780,000 miles. He holds a Class B CDL from Ohio. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Byler, 53, has complete loss of vision in his left eye due to a traumatic incident in childhood. The visual acuity in his right eye is 20/20, and in his left eye, no light perception. Following an examination in 2015, his optometrist stated, “In my medical opinion with the use of side mirrors the patient should be able to operate a commercial vehicle.” Mr. Byler reported that he has driven straight trucks for 12 years, accumulating 360,000 miles, and tractor-trailer combinations for 8 years, accumulating 600,000 miles. He holds a Class A CDL from Pennsylvania. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Fawcett, 65, has a retinal detachment in his right eye due to a traumatic incident in 1976. The visual acuity in his right eye is no light perception, and in his left eye, 20/20. Following an examination in 2015, his ophthalmologist stated, “Mr. Fawcett has sufficient vision in his left eye to operate a commercial vehicle.” Mr. Fawcett reported that he has driven straight trucks for 45 years, accumulating 270,000 miles, and tractor-trailer combinations for 45 years, accumulating 450,000 miles. He holds a Class AM CDL from Pennsylvania. His driving record for the last 3 years shows 1 crash, for which he was not cited and to which he did not contribute, and no convictions for moving violations in a CMV.
Mr. Friesner, Jr., 47, has had optic nerve hypoplasia in his right eye since birth. The visual acuity in his right eye is counting fingers, and in his left eye, 20/20. Following an examination in 2015, his optometrist stated, “It is my medical opinion that Mr. Friesner has sufficient vision to perform the driving tasks required to operate a commercial vehicle.” Mr. Friesner reported that he has driven straight trucks for 7 years, accumulating 350,000 miles. He holds an operator's license from Ohio. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Glynn, 56, has a corneal transplant and a lensectomy with IOL implant in his left eye due to a traumatic incident in 1984. The visual acuity in his right eye is 20/20, and in his left eye, 20/70. Following an examination in 2015, his optometrist stated, “Harry Glynn has sufficient vision to operate a commercial vehicle in my opinion.” Mr. Glynn reported that he has driven straight trucks for 40 years, accumulating 480,000 miles. He holds a chauffer's license from Louisiana. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Gray, 51, has a prosthetic left eye due to a traumatic incident in 1995. The visual acuity in his right eye is 20/20, and in his left eye, no light perception. Following an examination in 2015, his optometrist stated, “It is my professional opinion that Mr. Gray can operate any vehicle safely.” Mr. Gray reported that he has driven straight trucks for 32 years, accumulating 1.6 million miles, and tractor-trailer combinations for 15 years, accumulating 375,000 miles. He holds a Class AMV CDL from Alabama. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Hinton, 63, has had amblyopia in his left eye since childhood. The visual acuity in his right eye is 20/20, and in his left eye, 20/300. Following an examination in 2015, his optometrist stated, “In summary, I see no reason to restrict Mr. Hinton's license to drive a commercial vehicle for any eye or vision related cause.” Mr. Hinton reported that he has driven straight trucks for 24 years, accumulating 72,000 miles. He holds a Class BM CDL from New York. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Knef, 53, has had amblyopia in his right eye since childhood. The visual acuity in his right eye is 20/400, and in his left eye, 20/30. Following an examination in 2015, his optometrist stated, “Since this is a longstanding condition, it does not affect his ability to drive a commercial vehicle.” Mr. Knef reported that he has driven straight trucks for 28 years, accumulating 1.9 million miles. He holds a Class B CDL from New Jersey. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. McDonnell, 24, has had amblyopia in his left eye since childhood. The visual acuity in his right eye is 20/20, and in his left eye, counting fingers. Following an examination in 2015, his optometrist stated, “In summary, in my opinion there is nothing vision or eye-related that should prevent Cody from obtaining his CDL and driving safely.” Mr. McDonnell reported that he has driven tractor-trailer combinations for 3 years. He holds a Class A CDL from Oregon. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Michalko, 25, has a macular hole in his left eye due to a traumatic incident in 2004. The visual acuity in
Mr. Ratayczak, 50, has had amblyopia in his left eye since childhood. The visual acuity in his right eye is 20/20, and in his left eye, 20/70. Following an examination in 2015, his optometrist stated, “In my medical opinion, Mr. Ratayczak has sufficient vision in both eyes to operate a commercial vehicle he uses for his job.” Mr. Ratayczak reported that he has driven straight trucks for 15 years, accumulating 496,500 miles. He holds a Class D operator's license from Wisconsin. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Rokes, 51, has had macular degeneration in his left eye since 2012. The visual acuity in his right eye is 20/20, and in his left eye, 20/400. Following an examination in 2015, his optometrist stated, “In my medical opinion, Mr. Rokes has sufficient vision to perform the driving tasks required to operate a commercial vehicle.” Mr. Rokes reported that he has driven straight trucks for 33 years, accumulating 297,000 miles, and tractor-trailer combinations for 33 years, accumulating 132,000 miles. He holds a Class A CDL from Iowa. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Roughton, 51, has had a retinal detachment in his left eye since birth. The visual acuity in his right eye is 20/20, and in his left eye, no light perception. Following an examination in 2015, his optometrist stated, “Again, Mr. Roughton has had this vision defect since birth and there are no new changes. I see no reason that it would affect his ability to continue driving or affect his DOT physical.” Mr. Roughton reported that he has driven straight trucks for 20 years, accumulating 160,000 miles, and tractor-trailer combinations for 20 years, accumulating 160,000 miles. He holds a Class A CDL from Missouri. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Simonsen, 53, has had corneal dystrophy in his right eye since childhood. The visual acuity in his right eye is 20/60, and in his left eye, 20/20. Following an examination in 2015, his ophthalmologist stated, “Patient sees well enough to drive a commercial vehicle.” Mr. Simonsen reported that he has driven straight trucks for 35 years, accumulating 1.23 million miles. He holds an operator's license from SC. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Tuttle, 43, has had refractive amblyopia in his right eye since childhood. The visual acuity in his right eye is 20/200, and in his left eye, 20/20. Following an examination in 2015, his optometrist stated, “I feel he does see well enough operate a commercial vehicle without glasses.” Mr. Tuttle reported that he has driven straight trucks for 15 years, accumulating 300,000 miles. He holds a Class DMB CDL from Kentucky. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Van Raalte, 57, had a retinal detachment in his left eye in 1985. The visual acuity in his right eye is 20/20, and in his left eye, 20/80. Following an examination in 2015, his optometrist stated, “In my opinion, Mr. Van Raalte has sufficient vision to perform the driving tasks required to operate a commercial vehicle.” Mr. Van Raalte reported that he has driven straight trucks for 30 years, accumulating 57,000 miles, and tractor-trailer combinations for 30 years, accumulating 255,000 miles. He holds a Class A CDL from Illinois. His driving record for the last 3 years shows no crashes and no convictions for moving violations in a CMV.
Mr. Wernimont, 59, has had a prosthetic left eye since 1979. The visual acuity in his right eye is 20/20, and in his left eye, no light perception. Following an examination in 2015, his optometrist stated, “I certify that in my medical opinion, Marvin has sufficient vision to perform the driving tasks required to operate a commercial vehicle.” Mr. Wernimont reported that he has driven straight trucks for 17 years, accumulating 510,000 miles, and tractor-trailer combinations for 17 years, accumulating 425,000 miles. He holds a Class A CDL from Iowa. His driving record for the last 3 years shows one crash, for which he was not cited and to which he did not contribute, and no convictions for moving violations in a CMV.
Mr. Yole, 45, has had amblyopia in his right eye since childhood. The visual acuity in his right eye is 20/60, and in his left eye, 20/20. Following an examination in 2015, his optometrist stated, “In my opinion, he has sufficient vision to perform the driving tasks required to operate a commercial vehicle.” Mr. Yole reported that he has driven tractor-trailer combinations for 9 years, accumulating 832,500 miles. He holds a Class AM CDL from Texas. His driving record for the last 3 years shows no crashes and 1 conviction for a moving violation in a CMV; he exceeded the speed limit by 6 mph.
FMCSA encourages you to participate by submitting comments and related materials.
If you submit a comment, please include the docket number for this notice, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. 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 the Agency can contact you if it has questions regarding your submission.
To submit your comment online, go to
FMCSA will consider all comments and material received during the comment period and may change this notice based on your comments.
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of denials.
FMCSA announces its denial of 345 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.
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 Federal vision standard for a renewable 2-year period if it finds “such an exemption would likely achieve a level of safety that is equivalent to or greater than the level that would be achieved absent such an exemption.” The procedures for requesting an exemption are set forth in 49 CFR part 381.
Accordingly, FMCSA evaluated 345 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 4 applicants did not have sufficient driving experience over the past 3 years under normal highway operating conditions:
The following 82 applicants had no experience operating a CMV:
The following 54 applicants did not have 3 years of experience driving a CMV on public highways with their vision deficiencies:
The following 34 applicants did not have 3 years of recent experience driving a CMV with the vision deficiency:
The following 17 applicants did not have sufficient driving experience during the past 3 years under normal highway operating conditions:
The following 3 applicants were charged with moving violations in conjunction with CMV accidents:
The following applicant, Lee R. Boykin, does not have sufficient peripheral vision in the better eye to qualify for an exemption.
The following 3 applicants had their commercial driver's licenses suspended during the previous 3-year period:
The following applicant, Paul E. Lawyer, did not have verifiable proof of CMV experience over the past 3 years under normal highway operating conditions that would serve as an adequate predictor of future safe performance.
The following 3 applicants contributed to an accident(s) while operating a CMV:
The following applicant, Daniel L. Morris, did not have an optometrist or ophthalmologist willing to make a statement that they are able to operate a CMV from a vision standpoint.
The following 35 applicants were denied for multiple reasons:
The following applicant, Elijah A. Allen, Jr., provided false documentation during the application process.
The following 6 applicants did not have stable vision for the entire 3-year period:
The following 3 applicants do not meet the vision standard in the better eye:
The following 44 applicants met the current federal vision standards. Exemptions are not required for applicants who meet the current regulations for vision:
The following 2 applicants held medical cards valid for less than six months:
The following 3 applicants drove interstate while restricted to intrastate:
The following 34 applicants will not be driving interstate, interstate commerce, or are not required to carry a DOT medical card:
Finally, the following 14 applicants perform transportation for the federal government, state, or any political sub-division of the state.
Office of Small and Disadvantaged Business Utilization (OSDBU), Office of the Secretary of Transportation. (OST), Department of Transportation (DOT).
Notice of Funding Availability for the Southwest Region SBTRC.
The Department of Transportation (DOT), Office of the Secretary (OST), Office of Small and Disadvantaged Business Utilization (OSDBU) announces the opportunity for; (1) business centered community-based organizations; (2) transportation-related trade associations; (3) colleges and universities; (4) community colleges or; (5) chambers of commerce, registered with the Internal Revenue Service as 501C(6) or 501C(3) tax-exempt organizations, to compete for participation in OSDBU's Small Business Transportation Resource Center (SBTRC) program in the Southwest Region (California, Nevada, Arizona, and Hawaii).
OSDBU will enter into Cooperative Agreements with these organizations to provide outreach to the small business community in their designated region and provide financial and technical assistance, business training programs, business assessment, management training, counseling, marketing and outreach, and the dissemination of information, to encourage and assist small businesses to become better prepared to compete for, obtain, and manage DOT funded transportation-related contracts and subcontracts at the federal, state and local levels. Throughout this notice, the term “small business” will refer to: 8(a), small disadvantaged businesses (SDB), disadvantaged business enterprises (DBE), women owned small businesses (WOSB), HubZone, service disabled veteran owned businesses (SDVOB), and veteran owned small businesses (VOSB). Throughout this notice, “transportation-related” is defined as the maintenance, rehabilitation, restructuring, improvement, or revitalization of any of the nation's modes of transportation.
Complete Proposals must be electronically submitted to OSDBU via email on or before March 25, 2016, 6:00 p.m. Eastern Standard Time (EST). Proposals received after the deadline will be considered non-responsive and will not be reviewed. The applicant is advised to request delivery receipt notification for email submissions. DOT plans to give notice of award for the competed region on or before April 4, 2016, by 6:00 p.m. (EST).
Applications must be electronically submitted to OSDBU via email at
For further information concerning this notice, contact Mr. Adam Dorsey, Program Analyst, U.S. Department of Transportation, Office of Small and Disadvantaged Business Utilization, 1200 New Jersey Avenue SE., Washington, DC 20590. Telephone: (202) 366-1930. Email:
The DOT established OSDBU in accordance with Public Law 95-507, an amendment to the Small Business Act and the Small Business Investment Act of 1958. The mission of OSDBU at DOT is to ensure that the small and disadvantaged business policies and goals of the Secretary of Transportation are developed and implemented in a fair, efficient and effective manner to serve small and disadvantaged businesses throughout the country. The OSDBU also administers the provisions of Title 49, Section 332, the Minority Resource Center (MRC) which includes the duties of advocacy, outreach and financial services on behalf of small and disadvantaged business and those certified under CFR 49 parts 23 and or 26 as Disadvantaged Business Enterprises (DBE) and the development of programs to encourage, stimulate, promote and assist small businesses to become better prepared to compete for, obtain and manage transportation-related contracts and subcontracts.
The Regional Assistance Division of OSDBU, through the SBTRC program, allows OSDBU to partner with local organizations to offer a comprehensive delivery system of business training, technical assistance and dissemination of information, targeted towards small business transportation enterprises in their regions.
The national SBTRC program utilizes Cooperative Agreements with chambers of commerce, trade associations, educational institutions and business-centered community based organizations to establish SBTRCs to provide business training, technical assistance and information to DOT grantees and recipients, prime contractors and subcontractors. In order to be effective and serve their target audience, the SBTRCs must be active in the local transportation community in order to identify and communicate opportunities and provide the required technical assistance. SBTRCs must already have, or demonstrate the ability to, establish working relationships with the state and local transportation agencies and technical assistance agencies (
Effective outreach is critical to the success of the SBTRC program. In order for their outreach efforts to be effective, SBTRCs must be familiar with DOT's Operating Administrations, its funding sources, and how funding is awarded to DOT grantees, recipients, contractors, subcontractors, and its financial assistance programs. SBTRCs must provide outreach to the regional small business transportation community to disseminate information and distribute DOT-published marketing materials, such as Short Term Lending Program (STLP) Information, Bonding Education Program (BEP) information, SBTRC brochures and literature, DOT Procurement Forecasts; Contracting with DOT booklets, Women and Girls in Transportation Initiative (WITI) information, and any other materials or resources that DOT or OSDBU may develop for this purpose. To maximize outreach, the SBTRC may be called upon to participate in regional and national conferences and seminars. Quantities of DOT publications for on-hand inventory and dissemination at conferences and seminars will be available upon request from the OSDBU office.
The purpose of this Request For Proposal (RFP) is to solicit proposals from transportation-related trade associations, chambers of commerce, community based entities, colleges and universities, community colleges, and any other qualifying transportation-related non-profit organizations with the desire and ability to partner with OSDBU to establish and maintain an SBTRC.
It is OSDBU's intent to award a Cooperative Agreement to one organization in the Southwest Region, from herein referred to as “region”, in this solicitation. However, if warranted, OSDBU reserves the option to make multiple awards to selected partners. OSDBU also reserves the right to modify geographical area covered by the Southwest Region SBTRC. Proposals submitted for a region must contain a plan to service the states throughout the Southwest Region (California, Arizona, Nevada, and Hawaii), not just the state or immediate local geographical area where the SBTRC is headquartered. The SBTRC headquarters must be established in one of the designated states within the Southwest Region (California, Arizona, Nevada, and Hawaii).
Program requirements and selection criteria, set forth in Sections 2 and 4 respectively, indicate that the OSDBU intends for the SBTRC to be multidimensional; that is, the selected organization must have the capacity to effectively access and provide supportive services to the broad range of
Cooperative agreement awards will be distributed to the region(s) as follows:
Cooperative agreement awards by region are based upon an analysis of DBEs, Certified Small Businesses, and US DOT transportation dollars in each region.
It is OSDBU's intent to maximize the benefits received by the small business transportation community through the SBTRC. Funding will reimburse an on-site Project Director for
The cooperative agreement will be awarded for a period of 12 months (one year) with options for two (2) additional one year periods, at the discretion of OSDBU. OSDBU will notify the SBTRC of our intention to exercise an option year or not to exercise an option year 30 days in advance of expiration of the current year. Upon exercising the first option year of the Cooperative Agreement, OSDBU will renew the SBTRC with a 3% funding increase. Upon exercising the second option year, OSDBU will renew the SBTRC with a 1% increase from the first option year.
DOT is authorized under 49 U.S.C.§ 332(b)(4), (5) & (7) to design and carry out programs to assist small disadvantaged businesses in getting transportation-related contracts and subcontracts; develop support mechanisms, including management and technical services, that will enable small disadvantaged businesses to take advantage of those business opportunities; and to make arrangements to carry out the above purposes.
To be eligible, an organization must be an established, nonprofit, community-based organization, transportation-related trade association, chamber of commerce, college or university, community college, and any other qualifying transportation-related non-profit organization which has the documented experience and capacity necessary to successfully operate and administer a coordinated delivery system that provides access for small businesses to prepare and compete for transportation-related contracts.
In addition, to be eligible, the applicant organization must:
(A) Be an established 501C(3) or 501C(6) tax-exempt organization and provide documentation as verification. No application will be accepted without proof of tax-exempt status;
(B) Have at least one year of documented and continuous experience prior to the date of application in providing advocacy, outreach, and technical assistance to small businesses within the region in which proposed services will be provided. Prior performance providing services to the transportation community is preferable, but not required; and
(C) Have an office physically located within the proposed city in the designated headquarters state in the region for which they are submitting the proposal that is readily accessible to the public.
1. Conduct an assessment of small businesses in the SBTRC region to determine their training and technical assistance needs, and use information that is available at no cost to structure programs and services that will enable small businesses to become better prepared to compete for and receive transportation-related contract awards.
2. Contact other federal, state and local government agencies, such as the U.S. Small Business Administration (SBA), state and local highway agencies, state and local airport authorities, and transit authorities to identify relevant and current information that may support the assessment of the regional small business transportation community needs.
1. Utilize OSDBU's Intake Form to document each small business assisted by the SBTRC and type of service(s) provided. A complete list of businesses that have filled out the form shall be submitted as part of the SBTRC report, submitted via email to the Regional Assistance Division on a regular basis (using the SBTRC Report). This report will detail SBTRC activities and performance results. The data provided must be supported by the narrative (if asked).
2. Ensure that an array of information is made available for distribution to the small business transportation community that is designed to inform and educate the community on DOT/OSDBU services and opportunities.
3. Coordinate efforts with OSDBU in order to maintain an on-hand inventory of DOT/OSDBU informational materials for general dissemination and for distribution at transportation-related conferences and other events.
1. Collaborate with agencies, such as State, Regional, and Local Transportation Government Agencies, SBA, U.S. Department of Commerce's Minority Business Development Centers (MBDCs), Service Corps of Retired Executives (SCORE), Procurement Technical Assistance Centers (PTACs), and Small Business Development Centers (SBDCs), to offer a broad range of counseling services to transportation-related small business enterprises.
2. Create a technical assistance plan that will provide each counseled participant with the knowledge and skills necessary to improve the management of their own small business to expand their transportation-related contracts and subcontracts portfolio.
3. Provide a minimum of
1. Establish a Regional Planning Committee consisting of at least 10 members that includes representatives from the regional community and federal, state, and local agencies. The
2. Provide a forum for the federal, state, and local agencies to disseminate information about upcoming DOT procurements and SBTRC activities.
3. Hold either monthly or quarterly meetings at a time and place agreed upon by SBTRC and planning committee members (conference calls and/or video conferences are acceptable).
4. Use the initial session hosted by the SBTRC to explain the mission of the committee and identify roles of the staff and the members of the group.
5. Responsibility for the agenda and direction of the Planning Committee should be handled by the SBTRC Project Director or his/her designee.
1. Utilize the services of the System for Award Management (SAM) and other sources to construct a database of regional small businesses that currently or may in the future participate in DOT direct and DOT funded transportation related contracts, and make this database available to OSDBU, upon request.
2. Utilize the database of regional transportation-related small businesses to match opportunities identified through the planning committee forum, FedBiz Opps (a web-based system for posting solicitations and other Federal procurement-related documents on the Internet), and other sources to eligible small businesses and inform the small business community about those opportunities.
3. Develop a “targeted” database of firms (100-150) that have the capacity and capabilities, and are ready, willing and able to participate in DOT contracts and subcontracts immediately. This control group will receive ample resources from the SBTRC,
4. Identify regional, state and local conferences where a significant number of small businesses, with transportation related capabilities, are expected to be in attendance. Maintain and submit a list of those events to the Regional Assistance Division for review and posting on the OSDBU Web site on a regular basis. Clearly identify the events designated for SBTRC participation and include recommendations for OSDBU participation. This information can be submitted as part of the SBTRC Report.
5. Conduct outreach and disseminate information to small businesses at regional transportation-related conferences, seminars, and workshops. In the event that the SBTRC is requested to participate in an event, the OSDBU will send DOT materials, the OSDBU banner and other information that is deemed necessary for the event.
6. Submit a conference summary report within the `Events' section of the SBTRC Report. The conference summary report should summarize the activity, contacts made, outreach results, and recommendations for continued or discontinued participation in future similar events sponsored by that organization.
7. Upon request by OSDBU, coordinate efforts with DOT's grantees and recipients at the state and/or local levels to sponsor or cosponsor an OSDBU transportation related conference in the region (commonly referred to as “Small Business Summits”.
8. Participate in the SBTRC monthly teleconference call, hosted by the OSDBU Regional Assistance.
1. Work with STLP participating banks and if not available, other lending institutions to deliver a minimum of five (5) seminars/workshops per year on the STLP, and/or other financial assistance programs, to the transportation-related small business community. Seminars/workshops must cover the entire STLP/loan process, from completion of STLP/loan applications and preparation of the loan package.
2. Provide direct support, technical support, and advocacy services to potential STLP applicants to increase the probability of STLP loan approval and generate a minimum of four (4) completed STLP applications per year.
3. Provide direct support, technical support, and advocacy services to Small and Disadvantaged Businesses interested in obtaining a loan from another type of Government Lending Program. Government Lending Programs include Federal, State, and Local level programs. The SBTRC will be required to generate a minimum of three (3) completed Government Lending Program applications per year.
Work with OSDBU, bonding industry partners, local small business transportation stakeholders, and local bond producers/agents in your region to deliver a minimum of two (2) complete Bonding Education Programs and secure at least 3% of the total DBE contract value for each transportation project. The BEP consists of the following components; (1) the stakeholder's meeting; (2) the educational workshops component; (3) the bond readiness component; and (4) follow-on assistance to BEP participants to provide technical and procurement assistance based on the prescriptive plan determined by the BEP. For each BEP event, work with the local bond producers/agents in your region and the disadvantaged business participants to deliver a minimum of ten (10) disadvantaged business participants in the BEP with either access to bonding or an increase in bonding capacity. The programs will be funded separately and in addition to the amount listed in section 1.3 of this solicitation.
(A) Pursuant to Executive Order 13506, and 49 U.S.C. 332(b)(4) & (7), the SBTRC shall administer the WITI in their geographical region. The SBTRC shall implement the DOT WITI program as defined by the DOT WITI Policy. The WITI program is designed to identify, educate, attract, and retain women and girls from a variety of disciplines in the transportation industry. The SBTRC shall also be responsible for outreach activities in the implementation of this program and advertising the WITI program to all colleges and universities and transportation entities in their region. The WITI program shall be developed in conjunction with the skill needs of the USDOT, state and local transportation agencies and appropriate private sector transportation-related participants including, S/WOBs/DBEs, and women organizations involved in transportation. Emphasis shall be placed on establishing partnerships with transportation-related businesses. The SBTRC will be required to host 1 WITI event and attend at least 5 events where WITI is presented and marketed.
(B) Each region will establish a Women in Transportation Advisory Committee. The committee will provide a forum to identify and provide workable solutions to barriers that women-owned businesses encounter in transportation-related careers. The committee will have 5 members (including the SBTRC Project Director) with a 1 year membership. Meetings
(A) Provide consultation and technical assistance in planning, implementing and evaluating activities under this announcement.
(B) Provide orientation and training to the applicant organization.
(C) Monitor SBTRC activities, cooperative agreement compliance, and overall SBTRC performance.
(D) Assist SBTRC to develop or strengthen its relationships with federal, state, and local transportation authorities, other technical assistance organizations, and DOT grantees.
(E) Facilitate the exchange and transfer of successful program activities and information among all SBTRC regions.
(F) Provide the SBTRC with DOT/OSDBU materials and other relevant transportation related information for dissemination.
(G) Maintain effective communication with the SBTRC and inform them of transportation news and contracting opportunities to share with small businesses in their region.
(H) Provide all required forms to be used by the SBTRC for reporting purposes under the program.
(I) Perform an annual performance evaluation of the SBTRC. Satisfactory performance is a condition of continued participation of the organization as an SBTRC and execution of all option years.
Each proposal must be submitted to DOT's OSDBU in the format set forth in the application form attached as Appendix A to this announcement.
Any eligible organization, as defined in Section 1.6 of this announcement, will submit only one proposal per region for consideration by OSDBU.
Applications must be double spaced, and printed in a font size not smaller than 12 points. Applications will not exceed 35 single-sided pages, not including any requested attachments. All pages should be numbered at the top of each page. All documentation, attachments, or other information pertinent to the application must be included in a single submission. Proposal packages must be submitted electronically to OSDBU at
The applicant is advised to turn on request delivery receipt notification for email submission. Proposals must be received by DOT/OSDBU no later than March 25, 2016, 6:00 p.m. Eastern Standard Time (EST).
OSDBU will award the cooperative agreement on a best value basis, using the following criteria to rate and rank applications:
Applications will be evaluated using a point system (maximum number of points = 100);
The applicant must describe their strategy to achieve the overall mission of the SBTRC as described in this solicitation and service the small business community in their entire geographic regional area. The applicant must also describe how the specific activities outlined in Section 2.1 will be implemented and executed in the organization's regional area. OSDBU will consider the extent to which the proposed objectives are specific, measurable, time-specific, and consistent with OSDBU goals and the applicant organization's overall mission. OSDBU will give priority consideration to applicants that demonstrate innovation and creativity in their approach to assist small businesses to become successful transportation contractors and increase their ability to access DOT contracting opportunities and financial assistance programs. Applicants must also submit the estimated direct costs, other than labor, to execute their proposed strategy. OSDBU will consider the quality of the applicant's plan for conducting program activities and the likelihood that the proposed methods will be successful in achieving proposed objectives at the proposed cost.
The applicant must describe their established relationships within their geographic region and demonstrate their ability to coordinate and establish effective networks with DOT grant recipients and local/regional technical assistance agencies to maximize resources. OSDBU will consider innovative aspects of the applicant's approach and strategy to build upon their existing relationships and established networks with existing resources in their geographical area. The applicant should describe their strategy to obtain support and collaboration on SBTRC activities from DOT grantees and recipients, transportation prime contractors and subcontractors, the SBA, U.S. Department of Commerce's Minority Business Development Centers (MBDCs), Service Corps of Retired Executives (SCORE), Procurement Technical Assistance Centers (PTACs), Small Business Development Centers (SBDCs), State DOTs, and State highway supportive services contractors. In rating this factor, OSDBU will consider the extent to which the applicant demonstrates ability to be multidimensional. The applicant must demonstrate that they have the ability to access a broad range of supportive services to effectively serve a broad range of transportation-related small businesses within their respective geographical region. Emphasis will also be placed on the extent to which the applicant identifies a clear outreach strategy related to the identified needs that can be successfully carried out within the period of this agreement and a plan for involving the Planning Committee in the execution of that strategy.
The applicant must demonstrate that they have the organizational capability to meet the program requirements set forth in Section 2. The applicant organization must have sufficient resources and past performance experience to successfully provide outreach to the small business transportation resources in their geographical area and carry out the mission of the SBTRC. In rating this factor, OSDBU will consider the extent to which the applicant's organization has recent, relevant and successful experience in advocating for and addressing the needs of small businesses. Applicants will be given points for demonstrated past transportation-related performance. The applicant must also describe technical and administrative resources it plans to use in achieving proposed objectives. In their description, the applicant must describe their facilities, computer and technical facilities, ability to tap into volunteer staff time, and a plan for sufficient matching alternative financial resources to fund the general and administrative costs of the SBTRC. The applicant must also describe their
The applicant organization must provide a list of proposed personnel for the project, with salaries, fringe benefit burden factors, educational levels and previous experience clearly delineated. The applicant's project team must be well-qualified, knowledgeable, and able to effectively serve the diverse and broad range of small businesses in their geographical region. The Executive Director and the Project Director shall be deemed key personnel. Detailed resumes must be submitted for all proposed key personnel and outside consultants and subcontractors. Proposed key personnel must have detailed demonstrated experience providing services similar in scope and nature to the proposed effort. The proposed Project Director will serve as the responsible individual for the program. 100% of the Project Director's time must be dedicated to the SBTRC. Both the Executive Director and the Project Director must be located on-site. In this element, OSDBU will consider the extent to which the applicant's proposed Staffing Plan; (a) clearly meets the education and experience requirements to accomplish the objectives of the cooperative agreement; (b) delineates staff responsibilities and accountability for all work required and; (c) presents a clear and feasible ability to execute the applicant's proposed approach and strategy.
Applicants must submit the total proposed cost of establishing and administering the SBTRC in the applicant's geographical region for a 12 month period, inclusive of costs funded through alternative matching resources. The applicant's budget must be adequate to support the proposed strategy and costs must be reasonable in relation to project objectives. The portion of the submitted budget funded by OSDBU cannot exceed the ceiling outlined in Section 1.3: Description of Competition of this RFP per fiscal year. Applicants are encouraged to provide in-kind costs and other innovative cost approaches.
A review panel will score each application based upon the evaluation criteria listed above. Points will be given for each evaluation criteria category, not to exceed the maximum number of points allowed for each category. Proposals which are deemed non-responsive, do not meet the established criteria, or incomplete at the time of submission will be disqualified.
OSDBU will perform a responsibility determination of the prospective awardee in the region, which may include a site visit, before awarding the cooperative agreement.
Applicants must submit signed statements by key personnel and all organization principals indicating that they, or members of their immediate families, do not have a personal, business or financial interest in any DOT-funded transportation project, nor any relationships with local or state transportation agencies that may have the appearance of a conflict of interest.
Submitted proposals for the DOT, Office of Small and Disadvantaged Business Utilization's Small Business Transportation Resource Center Program must contain the following 12 sections and be organized in the following order:
Identify all parts, sections and attachments of the application.
Provide a
• The applicant's proposed SBTRC region and city and key elements of the plan of action/strategy to achieve the SBTRC objectives.
• The applicant's relevant organizational experience and capabilities.
Provide a narrative which contains specific project information as follows:
• The applicant will describe its understanding of the OSDBU's SBTRC program mission and the role of the applicant's proposed SBTRC in advancing the program goals.
• The applicant will describe specific outreach needs of transportation-related small businesses in the applicant's region and how the SBTRC will address the identified needs.
• Describe the applicant's plan of action/strategy for conducting the program in terms of the tasks to be performed.
• Describe the specific services or activities to be performed and how these services/activities will be implemented.
• Describe innovative and creative approaches to assist small businesses to become successful transportation contractors and increase their ability to access DOT contracting opportunities and financial assistance programs.
• Estimated direct costs, other than labor, to execute the proposed strategy.
• Describe established relationships within the geographic region and demonstrate the ability to coordinate and establish effective networks with DOT grant recipients and local/regional technical assistance agencies.
• Describe the strategy to obtain support and collaboration on SBTRC activities from DOT grantees and recipients, transportation prime contractors and subcontractors, the SBA, U.S. Department of Commerce's Minority Business Development Centers (MBDCs), Service Corps of Retired Executives (SCORE), Procurement Technical Assistance Centers (PTACs), Small Business Development Centers (SBDCs), State DOTs, and State highway supportive services contractors.
• Describe the outreach strategy related to the identified needs that can be successfully carried out within the period of this agreement and a plan for involving the Planning Committee in the execution of that strategy.
• Describe recent and relevant past successful performance in addressing the needs of small businesses, particularly with respect to transportation-related small businesses.
• Describe internal technical, financial management, and administrative resources.
• Propose a plan for sufficient matching alternative financial resources to fund the general and administrative costs of the SBTRC.
• List proposed key personnel, their salaries and proposed fringe benefit factors.
• Describe the education, qualifications and relevant experience of key personnel. Attach detailed resumes.
• Proposed staffing plan. Describe how personnel are to be organized for the program and how they will be used to accomplish program objectives. Outline staff responsibilities, accountability and a schedule for conducting program tasks.
• Outline the total proposed cost of establishing and administering the SBTRC in the applicant's geographical region for a 12 month period, inclusive of costs funded through alternative matching resources. Clearly identify the portion of the costs funded by OSDBU.
• Provide a brief narrative linking the cost proposal to the proposed strategy.
Complete the attached Standard Form 424B ASSURANCES-NON-CONSTRUCTION PROGRAMS identified as Attachment 1.
Complete form DOTF2307-1 DRUG-FREE WORKPLACE ACT CERTIFICATION FOR a GRANTEE OTHER THAN AN INDIVIDUAL identified as attachment 2 and Form DOTF2308-1 CERTIFICATION REGARDING LOBBYING FOR CONTRACTS, GRANTS, LOANS, AND COOPERATIVE AGREEMENTS identified as Attachment 3.
The statements must say that they, or members of their immediate families, do not have a personal, business or financial interest in any DOT-funded transportation projects, nor any relationships with local or state transportation agencies that may have the appearance of a conflict of interest.
Complete Standard Form 424 Application for Federal Assistance identified as Attachment 4.
PLEASE BE SURE THAT ALL FORMS HAVE BEEN SIGNED BY AN AUTHORIZED OFFICIAL WHO CAN LEGALLY REPRESENT THE ORGANIZATION.
Office of Small and Disadvantaged Business Utilization (OSDBU), Office of the Secretary of Transportation (OST), DOT.
Notice of request for comments.
The OSDBU invites the public to comment about our intention to request the Office of Management and Budget's (OMB) approval to renew an information collection. The collection involves the use of the SBTRC Regional Field Offices Intake Form (DOT F 4500). On November 12, 2015, OSDBU published a 60-day notice in the
We are required to publish this notice in the
Written comments should be submitted by: March 9, 2016.
Your comments should be identified by Docket No. DOT-OST-2015-0221 and may be submitted through one of the following methods:
•
•
•
Michelle Harris, Office of Small and Disadvantaged Business Utilization, Office of the Secretary, U.S. Department of Transportation, 1200 New Jersey Avenue SE., Room W56-444, Washington, DC 20590, (202) 366-2253 or
SBTRC's Regional Field Offices will collect information on small businesses, which includes Disadvantaged Business Enterprise (DBE), Women-Owned Small Business (WOB), Small Disadvantaged Business (SDB), 8(a), Service Disabled Veteran Owned Business (SDVOB), Veteran Owned Small Business (VOSB), HubZone, and types of services they seek from the Regional Field Offices. Services and responsibilities of the Field Offices include business analysis, general management and technical assistance and training, business counseling, outreach services/conference participation, short-term loan and bond assistance. The cumulative data collected will be analyzed by the OSDBU to determine the effectiveness of services provided, including counseling, outreach, and financial services. Such data will also be analyzed by the OSDBU to determine agency effectiveness in assisting small businesses to enhance their opportunities to participate in government contracts and subcontracts.
The Regional Field Offices Intake Form, (DOT F 4500) is used to enroll small business clients into the program in order to create a viable database of firms that can participate in government contracts and subcontracts, especially those projects that are transportation related. Each area on the fillable pdf form must be filled in electronically by the Field Offices and submitted every quarter to OSDBU. The Offices will retain a copy of each Intake Form for their records. The completion of the form is used as a tool for making decisions about the needs of the business, such as; referral to technical assistance agencies for help, identifying the type of profession or trade of the business, the type of certification that the business holds, length of time in business, and location of the firm. This
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Department, including whether the information will have practical utility; (b) the accuracy of the Department's estimate of the burden of the proposed information collection; (c) ways to enhance the quality, utility and clarity of the information collection; and (d) ways to minimize the burden of the collection of information on respondents, by the use of electronic means, including the use of automated collection techniques or other forms of information technology. The agency will summarize and/or include your comments in the request for OMB's clearance of this information collection.
The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended; and 49 CFR 1:48.
Electronic applications for must be received by 5:00 p.m. Eastern Time (ET), March 30, 2016.
A.
The CDFI Fund encourages Applicants to review the CMF interim rule, this NOFA, the environmental quality regulations, the CMF funding application (referred to hereafter as the “Application”, meaning the application submitted in response to this NOFA), and the Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards (2 CFR part 200; 78 FR 78590) (Uniform Administrative Requirements or UAR) for a complete understanding of the program. Each capitalized term in this NOFA is defined herein, in the interim rule, the Application, or the Uniform Administrative Requirements. Details regarding Application content requirements are found in the Application and related materials.
B.
C.
D.
A.
The CDFI Fund reserves the right, in its sole discretion, to provide a CMF Award in an amount other than that which the Applicant requests; however, the award amount will not exceed the Applicant's award request as stated in its Application.
B.
C.
D.
E.
A.
Any Applicant that does not meet the criteria in Table 1 is ineligible to apply for a CMF Award under this NOFA.
Further, the following describes additional considerations applicable to prior award Recipients or Allocatees under any CDFI Fund program:
B.
C.
D.
E.
(1) Debarment/Do not pay verification: The CDFI Fund will conduct a debarment check and will not consider an Application submitted by an Applicant if the Applicant is delinquent on any Federal debt.
The Do Not Pay Business Center was developed to support Federal agencies in their efforts to reduce the number of improper payments made through programs funded by the Federal government. The Do Not Pay Business Center provides delinquency information to the CDFI Fund to assist with the debarment check.
(2) Entities that Submit Applications Together with Affiliates: As part of the Application review process, the CDFI Fund considers whether Applicants are Affiliates, as such term is defined in 12 CFR 1807.104. If an Applicant and its Affiliates wish to submit Applications, they must do so collectively, in one Application; an Applicant and its Affiliates may not submit separate Applications. If Affiliated entities submit multiple Applications, the CDFI Fund will reject all such Applications received.
Furthermore, an Applicant that receives an award in this CMF round may not become an Affiliate of another Applicant that receives an award in this CMF round at any time after the submission of a CMF Application under this NOFA. This requirement will also be a term and condition of the Assistance Agreement (see additional Application guidance materials on the CDFI Fund's Web site at
(3) An Applicant will not be eligible to receive a CMF Award if the Applicant fails to demonstrate that its CMF Award would result in Eligible Project Costs that equals at least 10 times the amount of the CMF Award.
A.
B.
All Applications must be prepared using the English language and calculations must be made in U.S. dollars. Table 4 lists the required funding Application documents for the FY 2016 CMF Program Funding Round. The CDFI Fund reserves the right to request and review other pertinent or public information that has not been specifically requested in this NOFA or the Application. Information submitted by the Applicant that the CDFI Fund has not specifically been requested will not be reviewed or considered as part of the Application. The CDFI Fund will post to its Web site, at
The CDFI Fund strongly encourages Applicants to start the Grants.gov registration process as soon as possible (refer to the following link:
Applicants are only required to submit the OMB SF-424 Mandatory (Application for Federal Assistance) form in Grants.gov, as all other Application documents (listed in Table 4) will be submitted through AMIS. Applicants are encouraged to submit the SF-424 as early as possible through Grants.gov to provide time to resolve any submission problems. Applicants should contact Grants.gov directly with questions related to the registration or submission process as the CDFI Fund does not maintain the Grants.gov system.
C.
Pursuant to the Uniform Administrative Requirements, each Applicant must provide as part of its Application submission, a valid Dun & Bradstreet Universal Numbering System (DUNS) number. Any Applicant without a DUNS number will not be able to register and submit an Application in the Grants.gov system. Please allow sufficient time for Dun & Bradstreet to respond to inquiries and/or requests for DUNS numbers.
D.
Any entity applying for Federal grants or other forms of Federal financial assistance through Grants.gov must be registered in SAM before submitting its Application. The SAM registration process can take several weeks to complete. Applicants that have previously completed the SAM registration process must verify that their SAM accounts are current and active. Each Applicant must continue to maintain an active SAM registration with current information at all times during which it has an active Federal award or an Application under consideration by a Federal awarding agency. The CDFI Fund will not consider any Applicant that fails to properly register or activate its SAM account and, as a result, is unable to submit its Application by the Application deadline. Applicants must contact SAM directly with questions related to registration or SAM account changes as the CDFI Fund does not maintain this system. For more information about SAM, please visit
E.
All Application documents must be submitted through the Grants.gov and AMIS electronic systems. The CDFI Fund will not accept Applications via email, mail, facsimile, or other forms of communication, except in extremely rare circumstances that have been pre-approved by the CDFI Fund.
(1) Submission Deadlines: The following are the deadlines for submission of the documents related to the FY 2016 CMF Program Funding Round:
(2) Confirmation of Application Submission in Grants.gov and AMIS: Applicants are required to submit the OMB SF-424 Mandatory (Application for Federal Assistance) form through the Grants.gov system and must submit all other required Application materials through the AMIS Web site. Application materials submitted through both systems are due by the Application deadlines listed in Table 5. Applicants are strongly encouraged to submit the
(a) Grants.gov Submission Information: Each Applicant will receive an email from Grants.gov immediately after submitting the SF-424 confirming that the submission has entered the Grants.gov system. This email will contain a tracking number for the submitted SF-424. Within 48 hours, the Applicant will receive a second email which will indicate if the submitted SF-424 was either successfully validated or rejected with errors. However, Applicants should not rely on the email notification from Grants.gov to confirm that their SF-424 were validated. Applicants are strongly encouraged to use the tracking number provided in the first email to closely monitor the status of their SF-424 by contacting the helpdesk at Grants.gov directly. The Application materials submitted in AMIS are not officially accepted by the CDFI Fund until Grants.gov has validated the SF-424.
(b) Award Management Information System (AMIS) Submission Information: AMIS is a web-based portal where Applicants will directly enter their Application information and add required attachments listed in Table 4. AMIS will verify that the Applicant provided the minimum information required to submit an Application. Applicants are responsible for the quality and accuracy of the information and attachments included in the Application submitted in AMIS. The CDFI Fund strongly encourages the Applicant to allow sufficient time to confirm the Application content, review the material submitted, and remedy any issues prior to the Application deadline. Applicants can only submit one Application in AMIS. Upon submission, the Application will be locked and cannot be resubmitted, edited, or modified in any way. The CDFI Fund will not unlock or allow multiple Application submissions.
(3) Multiple Application Submissions: If an Applicant submits multiple Applications in Grants.gov, the CDFI Fund will only review the last Application submitted in Grants.gov. Applicants may only submit one Application through AMIS.
(4) Late Submission: The CDFI Fund will not accept an Application submitted after the Application deadline, except where the submission delay was a direct result of a Federal government administrative or technological error. In such cases, the Applicant must submit a request for acceptance of late Application submission and include documentation of the error no later than 2 business days after the Application deadline. The CDFI Fund will not respond to requests for acceptance of late Application submissions after that time period. Applicants must submit late Application submission requests to the CDFI Helpdesk at
(5) Intergovernmental Review: Not Applicable.
(6) Funding Restrictions: CMF Awards are limited by the following:
(a) A Recipient shall use CMF Award funds only for the eligible activities set forth in 12 CFR 1807.301 and as described in Section II.E of this NOFA and its Assistance Agreement.
(b) A Recipient may not disburse CMF Award funds to an Affiliate, Subsidiary, or any other entity, without the CDFI Fund's prior written approval.
(c) CMF Award funds shall only be paid to the Recipient.
(d) The CDFI Fund, in its sole discretion, may pay CMF Awards in amounts, or under terms and conditions, which are different from those requested by an Applicant.
(7) Other Submission Requirements: Each Applicant must register as an organization in AMIS and submit all required application materials through this portal. The Authorized Representative and/or Application point(s) of contact must be included as “Contacts” in the Applicant's AMIS account. The Authorized Representative must also be a “user” in AMIS and must electronically sign the Application prior to submission through AMIS. An Applicant that fails to properly register and update its AMIS account may miss important communications from the CDFI Fund or fail to submit an Application successfully.
A.
All eligible funding Applications will be reviewed through a multi-phase review process that includes both quantitative and qualitative reviews, as outlined below.
(1) Quantitative Review: First, the CDFI Fund will undertake an initial review of all Applications based on the following quantitative factors:
(a) The Applicant's organizational capacity, as measured by an evaluation of whether the Applicant's projected activities are reasonable given its track record, quality of its loan portfolio and financial health (40 points);
(b) The Applicant's commitments to Projects, beyond the minimum criteria, resulting in Affordable Housing for Low-Income, Very-Low- and Extremely Low-Income Families (30 points);
(c) The portion of the Applicant's commitments to generate the required 10:1 leverage ratio in Eligible Project Costs representing private capital and the portion of the leveraged funds representing third-party capital (30 points).
Applicants will receive a quantitative review score up to 100 points based on these factors. Applicants will be grouped into two categories: (1) Those with a maximum Non-Metropolitan investment of 50 percent or greater and (2) all other Applicants. Applicants in each category will be ranked according to their quantitative review score. The top 70 percent of Applicants in each category will be forwarded to the next level of review. The CDFI Fund reserves the right to forward additional Applicants to the qualitative review phase in order to ensure that a diversity of geographies are served by the Applicants reviewed in the qualitative review phase.
(2) External Application Review: Applications that pass the quantitative review process will be separately scored by one or more external non-Federal reviewers who are selected based on criteria that include: A professional background in affordable housing, community and economic development finance; experience reviewing financial statements of all CDFI institution types; and experience performing underwriting of affordable housing and economic development projects. Reviewers must complete the CDFI Fund's conflict of interest process and be approved by the CDFI Fund.
Reviewers will be assigned a set number of Applications to review. The reviewer will provide a score for each of the Applications that were reviewed, in accordance with the scoring criteria outlined in Section V.A of this NOFA and the Application materials.
Applications will be evaluated across four primary areas:
(3) Business Strategy (25 points): The Applicant must provide a detailed strategy for implementing its CMF Award.
(a) The Applicant is required to identify and describe, among other things:
(i) Its track record of financing affordable housing and related activities, or economic development activities, if applicable;
(ii) A description of the marketplace gaps in financing available for affordable housing in its proposed Service Area(s);
(iii) Its proposed eligible activities and a description of the types of financing that will be offered; and
(iv) Its pipeline of proposed Projects and activities.
(b) An Applicant will generally be scored more favorably in this section to the extent that it: Clearly identifies market gaps and proposes eligible activities to address those gaps through the use of its CMF Award; describes effective plans to provide financing that would not otherwise be available to finance and support Affordable Housing Activities and (if applicable) Economic Development Activities; proposes activities that are consistent with the Applicant's track record; and provides a detailed and viable pipeline of potential eligible Affordable Housing activities and (if applicable) Economic Development Activities.
(4) Leveraging Strategy (25 points): The Applicant must demonstrate its ability to leverage a CMF Award, particularly from private sources.
(a) To this end, the Applicant must identify and describe, among other things, its anticipated strategy for leveraging dollars, including both private capital and public funds:
(i) At the pre-investment stage (
(ii) Through reinvestment of CMF Award dollars during the Investment Period into additional Projects (
(iii) At the project level (
(b) An Applicant will generally score more favorably in this section to the extent that:
(i) A higher percentage of its leveraged funds come from private sources and from third-party capital;
(ii) It utilizes strategies for leveraging funds at the Applicant level (pre-investment stage and reinvestment), as opposed to solely at the Project level; and
(iii) It demonstrates a track record of leveraging funds in a similar manner.
(5) Community Impact (25 points): The Applicant must clearly describe the persons and communities the Applicant intends to serve and demonstrate a track record of serving those persons and/or communities.
(a) For rental Projects, beyond the threshold of 20 percent of units per Project, an Applicant will generally score more favorably to the extent it proposes to use its CMF Award and leveraged funds to produce a greater proportion of the total number of units financed with these funds to be occupied by Very Low-Income Families and/or Extremely Low-Income Families.
(b) For Homeownership Projects, beyond the threshold of 20 percent of units per Project, an Applicant will generally score more favorably to the extent it proposes to use its CMF Award and leveraged funds to produce a greater proportion of the total number of units financed with these funds to be occupied by Low-income Families.
(c) An Applicant will score more favorably to the extent that its strategy proposes Affordable Housing in areas of High Housing Need. Areas of High Housing Need are defined as census tracts where:
(i) At least 20 percent of households are Very Low-Income renters paying more than half their income for rent; or
(ii) Are high poverty neighborhoods (where greater than 20 percent of households have incomes below the poverty rate) with a rental vacancy rate of at least 10 percent; or
(iii) Are Underserved Rural Areas. The Applicant must also describe, and will score more favorably, the extent to which the Applicant's strategy will have positive community development and economic impacts, including expected impacts of strategies developed to complement formalized place-based strategies.
(d) For Economic Development activities, an Applicant will generally score more favorably to the extent that it commits to financing Economic Development Activities in Low-Income Areas.
(6) Organizational Capacity (25 points): The Applicant must demonstrate its ability and capacity to undertake its proposed activities, use its CMF Award successfully, and maintain compliance with its Assistance Agreement.
(a) To this end, the Applicant must identify and describe, among other things:
(i) Its management team and key staff;
(ii) The role of its governing board or advisory board;
(iii) Its procedures and systems to track and ensure compliance with the affordability and community impact commitments;
(iv) Its current financial health, including results of recent audits, and quality of its loan portfolio; and
(v) Its experience administering other public funds including Federal awards, if applicable.
(b) An Applicant will generally be scored more favorably to the extent that it:
(i) Demonstrates that its staff, Board members and other personnel have the requisite skills and experience to administer the CMF Award and maintain compliance with its Assistance Agreement;
(ii) Involves Low-Income persons or Low-Income community representatives in its decision-making process; and
(iii) Demonstrates a strong portfolio and financial health.
(1) Eligibility and Completeness Review: The CDFI Fund will review each Application to determine whether it is complete and the Applicant meets the eligibility requirements set forth in Section III.A above. An incomplete Application will be rejected; an Application that does not meet eligibility requirements will be rejected.
(2) Substantive Review: If an Application is deemed to be complete and the Applicant is determined to be eligible, the CDFI Fund will conduct the substantive review of the Application in accordance with the criteria and procedures described in this NOFA in Sections V.A(1) and V.A(2), the Application, and any Application guidance. As part of the review process, the CDFI Fund may contact the Applicant by telephone, email, mail, or through an on-site visit for the sole purpose of obtaining clarifying or confirming Application information. The CDFI Fund reserves the right to collect such additional information from Applicants as it deems appropriate. After submitting its Application, the Applicant will not be permitted to revise or modify its Application in any way nor attempt to negotiate the terms of an award. If contacted for clarifying or confirming information, the Applicant must respond within the time parameters established by the CDFI Fund.
(3)
In the case of an Applicant that has received awards from other Federal programs, the CDFI Fund reserves the right to contact officials from the appropriate Federal agency or agencies to determine whether the Recipient is in compliance with current or prior assistance agreements, and to take such information into consideration before making a CMF Award. In the case of an Applicant that has previously received funding through any CDFI Fund program, the CDFI Fund will consider and may, in its discretion, deduct up to 5 points from the external reviewer score for those Applicants (or their Affiliates) that, within 24 months prior to the Application deadline, are late in meeting reporting requirements for existing awards. The CDFI Fund may also bar from consideration an Applicant that has, in any proceeding instituted against the Applicant in, by, or before any court, governmental, or administrative body or agency, received a final determination within the last 3 years indicating that the Applicant has discriminated on the basis of race, color, national origin, disability, age, marital status, receipt of income from public assistance, religion, or sex.
(4) Selection: Once Applications have been internally evaluated and preliminary award determinations have been made, the Applications will be forwarded to a selecting official for a final award determination. After preliminary award determinations are made, the selecting official will review the list of potential Recipients to determine whether the Recipient pool meets the following statutory objectives:
(a) The potential Recipients' proposed Service Area collectively represent broad geographic coverage throughout the United States; and
(b) The potential Recipients' proposed activities equitably represent both Metropolitan and Non-Metropolitan areas, as defined in the Application.
To the extent practicable, the CDFI Fund reserves the right to make alterations to CMF Award amounts and/or to the CMF Recipient pool if deemed necessary to provide these desired outcomes. In cases where the selecting official's award determination varies significantly from the initial CMF Award amount recommended by the CDFI Fund staff review, the CMF Award recommendation will be forwarded to a reviewing official for final determination. The CDFI Fund, in its sole discretion, reserves the right to reject an Application and/or adjust CMF award amounts as appropriate based on information obtained during the review process.
(c) Insured Depository Institution Applicants: In the case of Applicants that are Insured Depository Institutions or Insured Credit Unions, the CDFI Fund will consider safety and soundness information from the Appropriate Federal or State Banking Agency. If the Applicant is a CDFI Depository Institution Holding Company, the CDFI Fund will consider information provided by the Appropriate Federal or State Banking Agencies about both the CDFI Depository Institution Holding Company and the CDFI Certified Insured Depository Institution that will expend and carry out the award. If the Appropriate Federal Banking Agency or Appropriate State Agency identifies safety and soundness concerns, the CDFI Fund will assess whether the concerns cause or will cause the Applicant to be incapable of undertaking the activities for which funding has been requested.
(5) Right of Rejection: The CDFI Fund reserves the right to reject an Application if information (including administrative errors) comes to the attention of the CDFI Fund that adversely affects an Applicant's eligibility for an award, adversely affects the CDFI Fund's evaluation or scoring of an Application, or indicates fraud or mismanagement on the Applicant's part. If the CDFI Fund determines that any portion of the Application is incorrect in any material respect, the CDFI Fund reserves the right, in its sole discretion, to reject the Application. The CDFI Fund reserves the right to change its eligibility and evaluation criteria and procedures, if the CDFI Fund deems it appropriate. If said changes materially affect the CDFI Fund's award decisions, the CDFI Fund will provide information regarding the changes through the CDFI Fund's Web site. There is no right to appeal the CDFI Fund's award decisions. The CDFI Fund's award decisions are final.
(6) Anticipated Award Announcement: The CDFI Fund anticipates making CMF Award announcements in Spring 2016.
A.
B.
If the Recipient's certification status as a CDFI changes, the CDFI Fund reserves the right, in its sole discretion, to re-calculate the CMF Award, modify the Notice of Award, and modify the Assistance Agreement based on the Recipient's non-CDFI status.
By executing an Assistance Agreement, the Recipient agrees that, if the CDFI Fund becomes aware of any information (including an administrative error) prior to the Effective Date of the Assistance Agreement that either adversely affects the Recipient's eligibility for an CMF Award, or adversely affects the CDFI Fund's evaluation of the Award Recipient's Application, or indicates fraud or mismanagement on the part of the Recipient, the CDFI Fund may, in its discretion and without advance notice to the Recipient, terminate the Assistance Agreement or take other actions as it deems appropriate.
The CDFI Fund reserves the right, in its sole discretion, to rescind an award if the Recipient fails to return the Assistance Agreement, signed by the authorized representative of the award Recipient, and/or provide the CDFI Fund with any other requested documentation, within the CDFI Fund's deadlines.
In addition, the CDFI Fund reserves the right, in its sole discretion, to terminate and rescind the Assistance Agreement and the award made under this NOFA for any criteria described in the following table:
C.
(1) The Assistance Agreement will set forth certain required terms and conditions of the CMF Award, which will include, but not be limited to:
(a) The amount of the award;
(b) The approved uses of the award;
(c) The approved Service Area in which the award may be used;
(d) Performance goals and measures; and
(e) Reporting requirements for all Recipients.
(2) The Assistance Agreement shall provide that, prior to any determination by the CDFI Fund that a Recipient has failed to comply substantially with the Act, the interim rule, or the environmental quality regulations, the CDFI Fund shall provide the Recipient with reasonable notice and opportunity for hearing. For failure by the Recipient to comply substantially with the Assistance Agreement, the CDFI Fund may:
(a) Require changes in the performance goals set forth in the Assistance Agreement;
(b) Reduce or terminate the CMF Award; or
(c) Require repayment of any CMF Award that has been distributed to the Recipient.
(3) The Assistance Agreement shall also provide that, if the CDFI Fund determines noncompliance with the terms and conditions of the Assistance Agreement on the part of the Recipient, the CDFI Fund may:
(a) Bar the Recipient from reapplying for any assistance from the CDFI Fund; or
(b) Take such other actions as the CDFI Fund deems appropriate or as set forth in the Assistance Agreement.
(4) In addition to entering into an Assistance Agreement, each Applicant selected to receive a CMF Award must furnish to the CDFI Fund an opinion from its legal counsel, the content of which will be further specified in the Assistance Agreement, which may include, among other matters, an opinion that:
(a) The Recipient is duly formed and in good standing in the jurisdiction in which it was formed and the jurisdiction(s) in which it transacts business;
(b) The Recipient has the authority to enter into the Assistance Agreement and undertake the activities that are specified therein;
(c) The Recipient has no pending or threatened litigation that would materially affect its ability to enter into and carry out the activities specified in the Assistance Agreement;
(d) The Recipient is not in default of its articles of incorporation or formation, bylaws or operating agreements, other organizational or establishing documents, or any agreements with the Federal government; and
(e) The CMF affordability restrictions that are to be imposed by deed restrictions, covenants running with the land, or other CDFI Fund approved mechanisms are recordable and enforceable under the laws of the State and locality where the Recipient will undertake its CMF activities.
D.
E.
The CDFI Fund may collect information from each Recipient including, but not limited to, an Annual Report with the following components:
Each Recipient is responsible for the timely and complete submission of the annual reporting documents. The CDFI Fund will use such information to monitor each Recipient's compliance with the requirements set forth in the Assistance Agreement and to assess the impact of the CMF. The CDFI Fund reserves the right, in its sole discretion, to modify these reporting requirements if it determines it to be appropriate and necessary; however, such reporting requirements will be modified only after notice to Recipients.
F.
The cost principles used by Recipients must be consistent with Federal cost principles, must support the accumulation of costs as required by the principles, and must provide for adequate documentation to support costs charged to the CMF Award. In addition, the CDFI Fund will require Recipients to: Maintain effective internal controls; comply with applicable statutes, regulations, and the Assistance Agreement; evaluate and monitor compliance; take action when not in compliance; and safeguard personally identifiable information.
A.
B.
For Information Technology support, the preferred method of contact is to submit a Service Request (SR) within AMIS. For the SR, select “General Inquiry” for the record type and select “Cross Program-AMIS technical problem” for the type.
C.
Pub. L. 110-289. 12 U.S.C. 4701, 12 CFR part 1805, 12 CFR part 1807, 12 CFR part 1815, 12 U.S.C. 4502.
Office of the Comptroller of the Currency (OCC), Treasury.
Notice and request for comment.
The OCC, 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 a continuing information collection, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35) (PRA).
Under the PRA, Federal agencies are required to publish notice in the
In accordance with the requirements of the PRA, the OCC may not conduct or sponsor, and the respondent is not required to respond to, an information collection unless it displays a currently valid Office of Management and Budget (OMB) control number. The OCC is soliciting comment concerning the renewal of its information collection titled, “Privacy of Consumer Financial Information.”
Comments must be received by April 8, 2016.
Because paper mail in the Washington, DC area and at the OCC is subject to delay, commenters are encouraged to submit comments by email, if possible. Comments may be sent to: Legislative and Regulatory Activities Division, Office of the Comptroller of the Currency, Attention: 1557-0216, 400 7th Street SW., Suite 3E-218, Mail Stop 9W-11, Washington, DC 20219. In addition, comments may be sent by fax to (571) 465-4326 or by electronic mail to
All comments received, including attachments and other supporting materials, are part of the public record and subject to public disclosure. Do not include any information in your comment or supporting materials that you consider confidential or inappropriate for public disclosure.
Shaquita Merritt, Clearance Officer, (202) 649-5490 or, for persons who are deaf or hard of hearing, TTY, (202) 649-5597, Legislative and Regulatory Activities Division, Office of the Comptroller of the Currency, 400 7th Street SW., Washington, DC 20219.
Under the PRA, Federal agencies must obtain approval from the OMB for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) to include agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal agencies to provide a 60-day notice in the
The OCC is proposing to extend OMB approval of the following information collection:
The Gramm-Leach-Bliley Act (Act) (Pub. L. 106-102) requires this information collection. Regulation P (12 CFR part 1016), a regulation promulgated by the Consumer Financial Protection Board (CFPB), implements the Act's notice requirements and restrictions on a financial institution's ability to disclose nonpublic personal information about consumers to nonaffiliated third parties.
The information collection requirements in 12 CFR part 1016 are as follows:
• That the national bank or Federal savings association discloses or reserves the right to disclose nonpublic personal information about its consumer to a nonaffiliated third party;
• That the consumer has the right to opt out of that disclosure; and
• A reasonable means by which the consumer may exercise the opt out right.
A national bank or Federal savings association provides a reasonable means to exercise an opt out right if it:
• Designates check-off boxes on the relevant forms with the opt out notice;
• Includes a reply form with the opt out notice;
• Provides electronic means to opt out; or
• Provides a toll-free number to opt out.
• Opt out—Consumers may direct that the national bank or Federal savings association not disclose nonpublic personal information about them to a nonaffiliated third party, other than permitted by §§ 1016.13-1016.15.
• Partial opt out—Consumer also may exercise partial opt out rights by selecting certain nonpublic personal information or certain nonaffiliated third parties with respect to which the consumer wishes to opt out.
Comments submitted in response to this notice will be summarized and included in the request for OMB approval. Comments are invited on:
(a) Whether the collection of information is necessary for the proper performance of the functions of the OCC, including whether the information has practical utility;
(b) The accuracy of the OCC'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 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.
Office of Foreign Assets Control, Treasury.
Notice.
The Treasury Department's Office of Foreign Assets Control (OFAC) is publishing the names of five individuals and three entities whose property and interests in property have been blocked pursuant to Executive Order (E.O.) 13288 of March 6, 2003, “Blocking Property of Persons Undermining Democratic Processes or Institutions in Zimbabwe,” as amended by E.O. 13391, “Blocking Property of Additional Persons Undermining Democratic Processes or Institutions in Zimbabwe,” and E.O. 13469 of July 25, 2008, “Blocking Property of Additional Persons Undermining Democratic Processes or Institutions in Zimbabwe.”
OFAC's actions described in this notice are effective as of February 3, 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
On February 3, 2016, the Acting Director of OFAC, in consultation with the State Department, determined that circumstances no longer warrant the inclusion of the following five individuals and three entities on OFAC's SDN list, and that these individuals and entities are no longer subject to the blocking provisions of Section 1(a) of E.O. 13288, as amended by E.O. 13991, and Section 1(a) of E.O. 13469.
Office of Foreign Assets Control, Treasury.
Notice.
The Department of the Treasury's Office of Foreign Assets Control (OFAC) is publishing the names of two individuals whose property and interests in property have been unblocked pursuant to the Foreign Narcotics Kingpin Designation Act (Kingpin Act, 21 U.S.C. 1901-1908, 8 U.S.C. 1182).
The unblocking and removal from the list of Specially Designated Nationals and Blocked Persons (SDN List) of the individuals identified in this notice whose property and interests in property were blocked pursuant to the Kingpin Act is effective on February 3, 2016.
Assistant Director, Sanctions Compliance & Evaluation, Department of the Treasury, Office of Foreign Assets Control, Washington, DC 20220, Tel: (202) 622-2420.
This document and additional information concerning OFAC are available from OFAC's Web site at
On December 3, 1999, the Kingpin Act was signed into law by the President of the United States. The Kingpin Act provides a statutory framework for the President to impose sanctions against significant foreign narcotics traffickers and their organizations on a worldwide basis, with the objective of denying their businesses and agents access to the U.S. financial system and to the benefits of trade and transactions involving U.S. persons and entities.
The Kingpin Act blocks all property and interests in property, subject to U.S. jurisdiction, that are owned or controlled by persons who have been identified by the President as significant foreign narcotics traffickers. In addition, the Act separately provides that the Secretary of the Treasury, in consultation with the Attorney General, the Director of the Central Intelligence Agency, the Director of the Federal Bureau of Investigation, the Administrator of the Drug Enforcement Administration, the Secretary of Defense, and the Secretary of State, may designate and block the property and interests in property, subject to U.S. jurisdiction, of persons who are found to be: (1) Materially assisting in, or providing financial or technological support for or to, or providing goods or services in support of, the international narcotics trafficking activities of a person designated pursuant to the Kingpin Act; (2) owned, controlled, or directed by, or acting for or on behalf of, a person designated pursuant to the Kingpin Act; or (3) playing a significant role in international narcotics trafficking. The authority to identify, designate, and block the property and interests in property of persons under the Kingpin Act is delegated to the Director of OFAC pursuant to 31 CFR 598.803.
On February 3, 2016, the Acting Director of OFAC removed from the SDN List the individuals listed below, whose property and interests in property were blocked pursuant to the Kingpin Act:
MATTHEWS, Glenroy Vingrove (a.k.a. MATHEW, Glenroy; a.k.a. MATTHEW, Glenroy Wingrove; a.k.a. MATTHEWS, Glen Roy), Frigate Bay, Saint Kitts and Nevis; DOB 26 Jul 1958; POB St Kitts and Nevis; Passport 047815 (Saint Kitts and Nevis) (individual) [SDNTK].
MIRCHI, Iqbal (a.k.a. MAMEN, Mohamed Iqbal; a.k.a. MEMON, Iqbal Mohammed; a.k.a. MERCHANT, Iqbal); DOB 25 Apr 1950; alt. DOB 12 Aug 1959; alt. DOB 13 Feb 1959; POB Bombay, India; Passport C-602033 (India); alt. Passport G-679302 (United Arab
Office of Foreign Assets Control, Treasury.
Notice.
The Treasury Department's Office of Foreign Assets Control (OFAC) is publishing updated information for one individual whose property and interests in property are blocked pursuant to Executive Order (E.O.) 13712, “Blocking Property of Certain Persons Contributing to the Situation in Burundi,” and whose name has been added to OFAC's list of Specially Designated Nationals and Blocked Persons (SDN List).
OFAC's action described in this notice was effective February 3, 2016.
The Department of the Treasury's Office of Foreign Assets Control: Assistant Director for Licensing, tel.: 202-622-2480, Assistant Director for Regulatory Affairs, tel.: 202-622-4855, Assistant Director for Sanctions Compliance & Evaluation, tel.: 202-622-2490; or the Department of the Treasury's Office of the Chief Counsel (Foreign Assets Control), Office of the General Counsel, tel.: 202-622-2410.
The SDN List and additional information concerning OFAC sanctions programs are available from OFAC's Web site (
On February 3, 2016, OFAC updated the identifying information for one individual whose property and interests in property are blocked pursuant to E.O. 13712. The updated identifying information for the individual is as follows:
NIYONZIMA, Joseph (a.k.a. NIJONZIMA, Joseph; a.k.a. NIYONZIMA, Mathias; a.k.a. NIYONZIMA, Salvator; a.k.a. “Kazungu”); DOB 02 Jan 1967; alt. DOB 06 Mar 1956; POB Kanyosha Commune, Mubimbi, Bujumbura-Rural Province, Burundi (individual) [BURUNDI].
Internal Revenue Service (IRS), Treasury.
Notice.
This notice is provided in accordance with IRC section 6039G of the Health Insurance Portability and Accountability Act (HIPPA) of 1996, as amended. This listing contains the name of each individual losing United States citizenship (within the meaning of section 877(a) or 877A) with respect to whom the Secretary received information during the quarter ending December 31, 2015. For purposes of this listing, long-term residents, as defined in section 877(e)(2), are treated as if they were citizens of the United States who lost citizenship.
Veterans Health Administration, Department of Veterans Affairs.
Notice.
In compliance with the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3521), this notice announces that the Veterans Health Administration (VHA), Department of Veterans Affairs, will submit the collection of information abstracted below to the Office of Management and Budget (OMB) for review and comment. The PRA submission describes the nature of the information collection and its expected cost and burden and includes the actual data collection instrument.
Written comments and recommendations on the proposed collection of information should be received on or before March 9, 2016.
Submit written comments on the collection of information through
Crystal Rennie, Enterprise Records Service (005R1B), Department of Veterans Affairs, 810 Vermont Avenue NW., Washington, DC 20420, (202) 632-7492 or email
Under the PRA of 1995 (Pub. L. 104-13; 44 U.S.C. 3501-3521), Federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. This request for comment is being made pursuant to Section 3506(c)(2)(A) of the PRA.
With respect to the following collection of information, VHA invites comments on: (1) Whether the proposed collection of information is necessary for the proper performance of VHA's functions, including whether the information will have practical utility; (2) the accuracy of VHA's estimate of the burden of the proposed collection of information; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or the use of other forms of information technology.
An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The
Following the large number of deployments and operations in Iraq and Afghanistan, the number of military members with mental health problems has been rising. All Veterans who need mental health services do not seek them it or receive them from the VA health care system. This study is to assess barriers to receiving mental health care services among veterans.
By direction of the Secretary.
Bureau of Land Management, Interior.
Proposed rule.
The Bureau of Land Management (BLM) is proposing new regulations to reduce waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on onshore Federal and Indian leases. The regulations would also clarify when produced gas lost through venting, flaring, or leaks is subject to royalties, and when oil and gas production used on site would be royalty-free. These proposed regulations would be codified at new 43 CFR subparts 3178 and 3179. They would replace the existing provisions related to venting, flaring, and royalty-free use of gas contained in the 1979 Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases, Royalty or Compensation for Oil and Gas Lost (NTL-4A), which are over 3 decades old.
Send your comments on this proposed rule to the BLM on or before April 8, 2016. The BLM is not obligated to consider any comments received after this date in making its decision on the final rule.
As explained later, the proposed rule would establish new information collection requirements that must be approved by the Office of Management and Budget (OMB). If you wish to comment on the information collection requirements in this proposed rule, please note that the OMB is required to make a decision concerning the collection of information contained in this proposed rule between 30 and 60 days after publication of this document in the
Comments on the information collection burdens:
Eric Jones at the BLM Moab Field Office, 82 East Dogwood Ave., Moab, UT 84532, or by telephone at 435-259-2117; or Timothy Spisak at the BLM Washington Office, 20 M Street SE., Room 2134LM, Washington, DC 20003, or by telephone at 202-912-7311. For questions relating to regulatory process issues, contact Faith Bremner at 202-912-7441.
Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 to contact these individuals during normal business hours. FIRS is available 24 hours a day, 7 days a week to leave a message or question with these individuals. You will receive a reply during normal business hours.
This proposed regulation aims to reduce the waste of natural gas from mineral leases administered by the BLM. This gas is lost during oil and gas production activities through flaring or venting of the gas, and equipment leaks. While oil and gas production technology has advanced dramatically in recent years, the BLM's requirements to minimize waste of gas have not been updated in over 30 years. The Mineral Leasing Act of 1920 (MLA) requires the BLM to ensure that lessees “use all reasonable precautions to prevent waste of oil or gas developed in theland . . . .” 30 U.S.C. 225. The BLM believes there are economical, cost-effective, and reasonable measures that operators should take to minimize waste, which will enhance our nation's natural gas supplies, boost royalty receipts for American taxpayers, tribes, and States, and reduce environmental damage from venting and flaring.
The BLM's onshore oil and gas management program is a major contributor to our nation's oil and gas production. The BLM manages more than 245 million acres of land and 700 million acres of subsurface estate, making up nearly a third of the nation's mineral estate. Domestic production from over 100,000 Federal onshore oil and gas wells accounts for 11 percent of the Nation's natural gas supply and 5 percent of its oil. In Fiscal Year (FY) 2014, operators produced 204.6 million barrels (bbl) of oil, 2 trillion cubic feet (Tcf) of natural gas, and 3.1 billion gallons of natural gas liquids (NGLs) from onshore Federal and Indian oil and gas leases. The production value of this oil and gas exceeded $27.2 billion and generated approximately $3.1 billion in royalties.
Over the past decade, the United States has experienced a dramatic increase in oil and natural gas production due to technological advances, such as hydraulic fracturing combined with directional and/or horizontal drilling. This boost in production has brought many benefits in the form of expanded and more secure domestic oil and gas supplies, lower oil and gas prices, increased economic activity, and greater royalty revenues for Federal, State and tribal governments. At the same time, the American public has not benefited from the full potential of this increased production, due to the flaring, venting, and leakage of significant quantities of gas during the production process. According to data reported to the Office of Natural Resources Revenue (ONRR), Federal and Indian onshore lessees and operators lost 375 billion cubic feet (Bcf) of natural gas between 2009 and 2014—enough gas to serve about 5.1 million households for a year, assuming 2009 usage levels.
Flaring, venting, and leaks waste a valuable resource that could be put to productive use, and deprive American taxpayers, tribes, and States of royalty revenues. In addition, the wasted gas may harm local communities and
The BLM oversees oil and gas activities under the authority of a variety of laws, including the MLA, the Mineral Leasing Act for Acquired Lands of 1947 (MLAAL), the Federal Oil and Gas Royalty Management Act (FOGRMA), the Federal Land Policy and Management Act of 1976 (FLPMA), the Indian Mineral Leasing Act of 1938 (IMLA), the Indian Mineral Development Act of 1982 (IMDA), and the Act of March 3, 1909.
Several oversight reviews, including reviews by the Inspector General of the Department of the Interior and the Government Accountability Office (GAO), have raised concerns about waste of gas, found that the BLM's existing requirements regarding venting and flaring are insufficient, expressed concerns about the “lack of price flexibility in royalty rates,”
This proposed rule would align the BLM's royalty rate for new competitive Federal oil and gas leases with the regime envisioned by the MLA, which specifies “a rate of
The BLM has engaged in substantial stakeholder outreach in the course of developing this proposal. In 2014, the BLM conducted a series of forums to consult with tribal governments and solicit stakeholder views to inform the development of this proposed rule, with public meetings (some of which were livestreamed) in Colorado, New Mexico, North Dakota, and Washington, DC.
The BLM conducted additional outreach with States where there is extensive oil and gas production from BLM-administered leases. We have carefully reviewed State regulations and guidance and consulted with State regulatory bodies that oversee aspects of oil and gas production to discuss their requirements and practices. The BLM intends to continue close interaction with State and tribal regulators.
The BLM is not the only entity to recognize the need to reduce flaring and
In addition, several States with BLM-administered lands and mineral interests have acted in this area. Colorado has adopted comprehensive statewide regulations to limit emissions of VOCs from venting and leaks from oil and gas production activities.
The oil and gas industry has also taken voluntary actions to reduce flaring and venting. Many of these efforts have been initiated by companies participating in Natural Gas STAR, a voluntary EPA-industry partnership program that encourages oil and natural gas companies to adopt cost-effective technologies and practices that improve operational efficiency and reduce methane emissions. Twenty-six companies in the production sector currently participate in Natural Gas STAR, and they reported that they achieved about 50 Bcf of methane emissions reductions in 2013.
Given these activities, it is important to ensure that updated BLM requirements do not subject operators to conflicting or redundant requirements. Thus, in addition to our outreach to States, we are coordinating closely with the EPA as it works to finalize its 40 CFR part 60 subpart OOOOa rulemaking.
The ongoing EPA and State regulatory activities do not, however, obviate the need for the BLM, in its role as a public land manager, to update its requirements governing flaring, venting, and leaks to ensure that the public's resources and assets are not wasted and are developed in a manner that provides for long term productivity and sustainability. First, the BLM has an independent legal responsibility, and a proprietary interest as a land manager, to oversee oil and gas production activities on Federal and Indian leases. The BLM has requirements in place, but as independent reviews have pointed out, the existing requirements pre-date, and thus do not account for, significant technological developments. Updating and clarifying the regulations will make them more effective, more transparent, and easier to understand and administer, and will reduce operators' compliance burdens in some respects. The BLM must ensure that it has modern, effective requirements to govern oil and gas operations on BLM-administered leases. Second, as a practical matter, neither the EPA nor State regulations adequately address the issue of waste of gas from BLM-administered leases. The EPA regulations are directed at air pollution reduction, not waste prevention; they focus largely on new sources; and they do not address all avenues for reducing waste (for example, they do not impose flaring limits for associated gas). Similarly, no State has established a comprehensive set of requirements addressing all three avenues for waste—flaring, venting, and leaks—and only a few States have significant requirements in even one of these areas. It is wholly within the BLM's statutory authority to address flaring, venting, and leaks in its capacity as a land manager with a responsibility to ensure the longevity and long term productivity of public lands and resources, including gas resources. Part I.B. of this preamble, below, offers a summary of the proposed rule's provisions, benefits, and costs, and parts V and VI of this preamble provide more detail about those provisions (part V) and impacts (part VI). Overall, the BLM estimates that the benefits of this rule would outweigh its costs by a significant margin. Under certain assumptions, for example, the rule is expected to produce net benefits ranging from $115 million to $188 million per year (assuming the EPA finalizes 40 CFR part 60 subpart OOOOa and calculating costs and cost savings using a 7 percent discount rate) or from $138 million to $232 million per year (assuming the EPA finalizes 40 CFR part 60 subpart OOOOa and calculating costs
The proposed rule would require operators to take various actions to reduce waste of gas, establish clear criteria for when flared gas would qualify as waste and therefore be subject to royalties, and clarify the on-site uses of gas that are exempt from royalties. The BLM has identified several key points in the oil and gas production process where waste-prevention actions would be most effective and least costly. Specifically, we propose to focus on reducing waste from the following aspects of the production process: Flaring of associated gas from development oil wells; gas leaks from equipment and facilities located at the well site, as well as from compressors located on the lease; operation of high-bleed pneumatic controllers and certain pneumatic pumps; gas emissions from vessels; downhole well maintenance and liquids unloading; and well drilling and completions. The following discussion summarizes the proposed requirements applicable to each of these aspects of the production process.
These requirements would impose annual costs and yield annual benefits, but both costs and benefits are expected to vary over time. Over the first few years, compliance activity (and associated costs and gas savings) would likely be highest. During this time, some operators would have to add or improve gas-capture capability, and some would have to replace existing equipment. After these transitional years, we expect that both compliance activities and gas savings from this rule would be significantly reduced.
In 2013, operators vented about 22 Bcf and flared at least 76 Bcf of natural gas from BLM-administered leases.
The BLM is proposing to prohibit venting of natural gas, except under certain conditions, including in emergencies, as would be defined in the regulations.
The primary alternative to flaring associated gas from oil wells is to capture, transport, and process that gas for sale, using the same technologies that are used for natural gas production. The capture and sale of associated gas is viable where there is sufficient gas production to offset the costs of connecting to or expanding existing pipeline infrastructure. In addition, technologies for capturing and using gas without a pipeline are becoming increasingly available. This capture infrastructure may include: Separating out NGLs or liquefying the natural gas (LNG), allowing the resulting liquids to be trucked off location; converting the gas into compressed natural gas (CNG) for use on-site or to be trucked off location; and using the gas to run micro-turbines to generate power for use on-site or for sale back to the grid.
Gas is flared under a variety of circumstances. Some circumstances, such as emergencies, can occur unplanned in the course of oil and gas production. Further, in a new field, operators and the midstream processing companies that commonly build and operate gas gathering and processing infrastructure may not have sufficient information about how much gas will be produced to invest in building gathering lines and processing plants. In other instances, however, operators may decide to focus on near-term oil production rather than investing in the gas capture and transmission infrastructure that would be necessary to realize a profit from the associated gas.
On BLM-administered leases, two situations result in substantial flaring of associated gas. In some areas, there is capture infrastructure, but the rate of new well construction is outpacing the infrastructure capacity. This accounts for the majority of flaring on BLM-administered leases. In other areas, capture and processing infrastructure has not yet been built out.
Currently, under NTL-4A, operators must seek BLM approval to flare on a case-by-case basis, with limited exceptions. Operators must provide economic data with each request, demonstrating that requiring the gas to be captured would “lead to the premature abandonment of recoverable oil reserves and ultimately to a greater loss of equivalent energy than would be recovered” if the flaring were approved. This approach results in a substantial amount of paper-work, but does not significantly limit flaring, as BLM has commonly, although not always, approved these requests.
The BLM proposes to simplify, clarify, and strengthen its approach to reducing flaring by establishing clear parameters for when routine flaring from development wells is allowed, and by setting a limit on the rate of flaring from individual wells. As a general matter, operators would no longer have to obtain permission for flaring on a case-by-case basis, provided they stay within the proposed prescribed limit.
Specifically, we propose to limit routine flaring of associated gas from development wells to 1,800 thousand cubic feet (Mcf) per month per well, averaged across all of the producing wells on a lease. This limit is similar to requirements in Wyoming and Utah, which limit flaring to 60 Mcf/day and 1,800 Mcf/month, respectively, unless the operator obtains State approval of a higher limit.
The BLM proposes to phase in the flaring limit over the first 2 years after the rule becomes effective, in recognition of the fact that some wells are flaring at rates considerably higher than 1,800 Mcf/month, not all wells will be able to use on-site capture technologies, and connecting to gas pipeline infrastructure may take some time. We propose that in the first year after the effective date of the rule, the flaring limit per well, averaged across all of the producing wells on a lease, would be 7,200 Mcf/month. In the second year, it would be 3,600 Mcf/month. The 1,800 Mcf/month limit would apply beginning in the third year of the rule.
The BLM is also proposing that prior to drilling a new development oil well, an operator would have to evaluate the opportunities and prepare a plan to minimize waste of associated gas from that well, and the operator would need to submit this plan along with the Application for Permit to Drill or Reenter (APD). The BLM proposes to require submission of a plan with specific content, to ensure that operators have carefully considered and planned for gas capture prior to drilling.
In addition to these requirements to reduce flaring, the BLM proposes to update existing royalty provisions by more specifically defining when a loss of gas would be considered “unavoidable” and royalty-free, and when it would be considered “avoidable” and subject to royalties. A loss of gas would be deemed unavoidable when an operator has complied with all applicable requirements and taken prudent and reasonable steps to avoid waste, and the gas is lost from any of the following specified operations or sources, subject to limits specified in the proposed regulations: Emergencies; well drilling, well completion and related operations; initial production tests and subsequent well tests; exploratory coalbed methane well dewatering; leaks; venting from pneumatic devices in the normal course of operation; evaporation from storage vessels; and downhole well maintenance and liquids unloading. A loss of gas would also be deemed unavoidable when gas is flared (or, in limited circumstances, vented) from a well that is not connected to gas capture infrastructure, provided the BLM has not otherwise determined that the loss of gas is avoidable, pursuant to the provisions of the 1,800 Mcf/month limit in § 3179.6. All losses of gas not specifically found to be unavoidable would be considered avoidable and subject to royalties. Thus, royalties would apply to associated gas flared from a development well that is already connected to capture infrastructure. Under these circumstances, operators have made an economic choice to flare, and that flaring should not be considered an unavoidable consequence of oil production.
Currently, there is a backlog of requests for approval to flare royalty-free pending with the BLM. By establishing clear categories for avoidable and unavoidable losses, and thus clarifying when gas may be flared without payment of royalties, the BLM aims to reduce the number of applications for approval to flare royalty-free and thereby reduce the burden on both operators and the BLM. The BLM could then use these administrative resources to process applications for permit to drill and right-of-way applications, and to conduct inspections, among other activities.
The costs and benefits of the flaring provisions are as follows. First, the rule proposes to require the metering of flared volumes when gas flaring meets or exceeds 50 Mcf/day for a flare stack or manifold. We estimate compliance costs ranging from $1.0-1.8 million per year when the capital costs of equipment are annualized with a 7 percent discount rate, or $0.9-1.6 million per year when the capital costs of equipment are annualized with a 3 percent discount rate.
For purposes of this analysis, we present costs and benefits using discount rates of 7% and 3% to annualize the costs of capital investments. OMB Circular A-94 (Revised) “Guidelines and Discount Rates for Benefit-Cost Analysis of Federal Programs,”
We estimate that the proposed flaring limits, including the 3-year phase-in period would affect an estimated 435-885 leases in any given year. These requirements could pose total costs of about $32-68 million per year (7 percent discount rate) or $26-43 million per year (3 percent discount rate). Because these requirements would drive additional capture of gas, the flaring limits are also projected to pose total cost savings (from the value of the captured gas) of about $40-58 million per year (7 percent discount rate) or $40-64 million per year (3 percent discount rate). We also estimate that they would increase natural gas production by 2.5-5.0 Bcf per year, and increase NGL production by 36-51 million gallons per year. The net benefits of these requirements are estimated to range from negative $10 to positive $8 million per year (7 percent discount rate) or $13-30 million per year (3 percent discount rate).
One significant source of the 22 Bcf of gas vented from Federal and Indian leases in 2013 is leakage. The BLM estimates that up to 4.35 Bcf of natural gas was lost in 2013 as a result of leaks or other fugitive emissions at operations on BLM-administered leases.
The BLM believes that LDAR programs are a cost-effective means of
The costs and benefits of the BLM's proposed LDAR requirements depend on the rest of the regulatory landscape. Assuming that the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking for new and modified sources,
If, for analytical purposes we assume a baseline in which EPA does not finalize its proposed LDAR requirements, we estimate the following impacts. We project that the proposed LDAR requirements would affect up to about 37,000-38,000 wellsites per year, and pose total costs of about $70-71 million per year (using 7 percent and 3 percent discount rates). These requirements are also projected to result in cost savings of about $12-18 million per year (using 7 percent and 3 percent discount rates), increase gas production by 3.9-4.0 Bcf per year, and reduce VOC emissions by 19,000 tpy. We estimate these proposed requirements would also reduce methane emissions by 68,000 tpy, producing monetized benefits of $75 million per year in 2017-2019, $88 million per year in 2020-2024, and $102 million in 2025 and 2026. Thus, we estimate that these proposed provisions would result in net benefits of $19-21 million per year in 2017-2019, $30-35 million per year in 2020-2024, and $43-48 million in 2025 and 2026.
These estimates represent the maximum likely impact. As noted previously, some operators currently have LDAR programs. This analysis accounts for existing State requirements in Colorado, Utah, and Wyoming, but it does not account for existing (voluntary or required) LDAR activities conducted by operators outside of those States. If we accounted for these existing activities, then the costs, emissions reductions, incremental production, and royalty estimates resulting from this proposed rule would be less than those shown.
Pneumatic controllers and pneumatic pumps are operated by gas pressure and emit gas as part of their normal operations. We estimate that on BLM-administered leases in 2013, about 5.4 Bcf of natural gas was lost from pneumatic controllers, and about 2.5 Bcf was lost from all pneumatic pumps.
EPA generally prohibits the use of new high-bleed pneumatic controllers,
The BLM is proposing to require operators to replace high-bleed pneumatic controllers with low-bleed or no-bleed pneumatic controllers within 1 year of the effective date of the final rule. This requirement would apply only to pneumatic controllers that are not subject to EPA regulations. The BLM also proposes exceptions to this requirement, including where the operator demonstrates, and the BLM concurs, that replacing the controller(s) would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. In making this determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease.
We estimate that the proposed pneumatic controller requirements would impact up to about 15,600 existing low-bleed pneumatic devices, and pose total costs of about $6 million per year (capital costs annualized using a 7 percent discount rate) or $5 million per year (capital costs annualized using a 3 percent discount rate). Because the sale of recovered gas is expected to offset the engineering costs of new controllers, the BLM expects that
For pneumatic pumps, the BLM is proposing to require the operator to either: (1) Replace a pneumatic chemical injection or diaphragm pump with a zero-emissions pump; or (2) Route the pneumatic chemical injection or diaphragm pump to a flare. This requirement would apply only to pneumatic pumps that are not subject to EPA regulations. In addition, an operator would be exempt from this requirement if it demonstrates, and the BLM concurs, that: (1) There is no flare already available on-site or routing to a flare device is technically infeasible; and (2) A zero-emission pneumatic pump is not a viable alternative to perform the required function. An operator would also be exempt if the operator demonstrates and the BLM concurs that replacing the pneumatic pump(s) would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. In making this determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease.
If the EPA finalizes its concurrent 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that these requirements would impact up to 8,775 existing pumps, posing total costs of about $2.5 million per year. They would also increase gas production by 0.46 Bcf per year and result in cost savings of about result in cost savings of $1.5-1.9 million per year (7 percent discount rate) or $1.75-2.15 million per year (3 percent discount rate). In addition, they are projected to reduce methane emissions by about 16,000 tpy, producing monetized benefits of $18 million per year in 2017-2019, $21 million per year in 2020-2024, and $24 million in 2025 and 2026. This would result in net benefits of $17 million per year in 2017-2019, $20 million per year in 2020-2024, and $23 million in 2025 and 2026, as well as reducing VOC emissions by about 4,000 tpy.
Assuming, for purposes of analysis, that EPA does not finalize the 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that the pneumatic pump requirements would affect up to about 8,775 existing pumps and about 75 new pumps per year, posing total costs of about $2.5-2.7 million per year (using 7 percent and 3 percent discount rates). They would also increase gas production by 0.5 Bcf per year and result in cost savings of about $1.5-2.2 million per year (using 7 percent and 3 percent discount rates). In addition, they are projected to reduce methane emissions by about 16,000-17,000 tpy, producing monetized benefits of $18 million per year in 2017-2019, $22 million per year in 2020-2024, and $26 million in 2025 and 2026. This would result in net benefits of $17 million per year in 2017-2019, $21-22 million per year in 2020-2024, and $25 million in 2025 and 2026, as well as reducing VOC emissions by about 4,000 tpy.
Vapors released from storage vessels are a lost source of energy and revenue, present safety concerns, and contribute to local air pollution and climate change. We estimate that 2.77 Bcf of natural gas was lost in 2013 from storage tank venting on Federal and Indian lands.
Tank vapors can be controlled by routing them to a flare or combustor, or by installing a vapor recovery unit (VRU). New and modified vessels used in oil and gas production are already subject to EPA emissions limits, which require that individual storage vessels with VOC emissions equal to or greater than 6 tpy achieve at least a 95 percent reduction in VOC emissions from baseline levels. Colorado and part of Wyoming have similar, somewhat more stringent, requirements for storage vessels.
The BLM proposes to address gas losses from existing storage vessels, which are not covered by the EPA standards. The BLM believes that reducing venting from existing storage vessels, which have higher rates of venting, is a reasonably cost-effective means of reducing gas losses. Rather than establishing new and separate standards for venting from existing vessels, we have been informed by operators that it would be easier to comply if we simply require existing vessels on BLM-administered leases to meet standards that are the same as the EPA standards that already apply to new and modified vessels on those leases. Additionally, there does not appear to be a uniform conversion factor that we could use to translate the VOC standards established by EPA, Colorado, and Wyoming to a whole gas standard. Depending on the content of a vessel, the same quantity of gas released from the vessel may contain different quantities of VOCs. Thus, even though the BLM is concerned about loss of
The BLM proposes to require that operators route VOC emissions from existing storage vessels subject to these requirements to combustion devices, continuous flares, or sales lines within 6 months after the effective date of the rule. The BLM would grant an exception to this requirement if the operator submits an economic analysis demonstrating—and the BLM agrees—that compliance would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. In making this determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease. Consistent with the EPA requirements for new vessels,
The BLM estimates that the proposed requirements would affect about 300 existing storage vessels on BLM-administered leases, and pose total costs of about $6 million per year (using 7 percent and 3 percent discount rates).
Over time, as pressure in a natural gas well drops, liquids often start accumulating at the bottom of the well, impeding gas production. Operators often remove or “unload” the liquids, but depending on the method, this process can release substantial quantities of natural gas into the environment. In particular, operators may allow the bottom-hole pressure to increase and then vent or “blow down” or “purge” the well. We estimate that 3.26 Bcf of natural gas was lost in 2013 during liquids unloading operations on Federal and Indian lands.
There are a wide variety of methods for liquids unloading, and technological developments, such as automated plunger lifts, now allow liquids to be unloaded with minimal loss of gas. The BLM believes that it is reasonable to expect operators to use these available technologies to minimize gas losses, and we believe that failure to minimize losses of gas from liquids unloading now constitutes waste.
For wells drilled after the effective date of the rule, the BLM is proposing to prohibit unloading liquids by simply purging the well (except in specified circumstances). The BLM believes that it is less costly to avoid purging altogether at new wells than at existing wells. In addition, the BLM is proposing to require specified best management practices to minimize venting from liquids unloading at both new and existing wells. Specifically, the operator would be required to be on-site during well purging events, unless the well has an automatic control system, and the operator would also be required to document liquids unloading events. This would allow the BLM to verify compliance, and it would provide additional information on the amounts of gas lost through these activities on Federal and Indian lands.
We estimate that the proposed liquids unloading requirements would affect up to about 1,550 existing wells and about 25 new wells per year, posing total costs of about $6 million per year (capital costs annualized using a 7 percent discount rate) or $5-6 million per year (capital costs annualized using a 3 percent discount rate). We project that they would increase gas production by roughly 2 Bcf per year, resulting in cost savings of about $7-8 million per year (using a 7 percent discount rate) or $7-10 million per year (using a 3 percent discount rate). In addition, these requirements are projected to reduce methane emissions by 30,000 to 34,000 tpy, producing monetized benefits of $33-34 million per year in 2017-2019, $41-43 million per year in 2020-2024, and $50-51 million in 2025 and 2026. Overall, we estimate that these provisions would produce net benefits of $35-52 million per year (using a 7 percent discount rate for costs and cost savings) or $35-55 million per year (using a 3 percent discount rate for costs and cost savings), and reduce VOC emissions by about 136,000 to 156,000 tpy.
Substantial quantities of gas can be lost during drilling, completion, and refracturing (sometimes referred to by the broader term “workover”) operations, and we estimate that in 2013, 2.1 Bcf of natural gas was lost during these operations on BLM-administered leases.
The EPA currently requires new hydraulically fractured and refractured gas wells to capture or flare gas that otherwise would be released during drilling and completion operations, and EPA has announced that it plans to extend these requirements to new hydraulically fractured and refractured oil wells. Nonetheless, the BLM believes that it is appropriate for the BLM to adopt its own requirements to minimize the waste of gas during well drilling and well completion and post-completion operations at hydraulically fractured or refractured wells and wells that are not fractured. The BLM has an independent statutory obligation to minimize waste of oil and gas resources on BLM-administered leases. As proposed, the BLM waste requirements for well drilling and completions would extend to both conventional and hydraulically fractured wells, and therefore would apply to a broader set of wells than the EPA regulations propose to cover. Also, the BLM anticipates that to the extent both sets of requirements applied, the BLM believes that an operator would satisfy both sets of requirements by either capturing or flaring the gas that would otherwise be released. Thus, the BLM is also proposing to allow an operator to demonstrate that it is in compliance with EPA requirements for control of gas from well completions in lieu of compliance with the BLM requirements. The BLM is coordinating closely with the EPA on the agencies' proposals, and the BLM expects to ensure that our final requirements would not impose additional burdens on an operator that complies with any EPA requirements on new well completions.
The proposed rule would require operators to: Flare gas generated during drilling operations, capture and sell that gas, use it in operations on the lease, or inject it into the well. We estimate that the rule would apply to about 3,000 wells per year. Based on our experience in the field, however, the BLM believes that operators are already controlling gas from drilling operations as a matter of safety and operating practice. Thus, we do not estimate costs associated with this requirement. Similarly, based on our professional experience in the field, we believe that operators are already controlling gas from workover operations on conventional wells as a matter of safety and operating practice, and there should be no compliance costs for this requirement.
The proposed rule would also require operators to reduce the emissions associated with well completions by capturing and selling associated gas, flaring it, using it in operations on the lease, or injecting it. This proposal would only impact well completions and workovers/refractures on conventional oil and gas wells and
If the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking, as we expect, then as a practical matter, this rule's completion requirements will only impact conventional well completions, because the EPA will regulate completions of new and modified hydraulically fractured oil and gas wells. We estimate that the BLM rule would impact between 115-150 completions per year and pose costs to the industry of less than $430,000 per year. There would be only
If, for purposes of analysis, we assume that EPA does not finalize its 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that these provisions would affect about 1,250 to 1,575 completions per year and pose total costs of about $8-12 million per year (using a 7 percent discount rate) or $12 million per year (using a 3 percent discount rate). We further estimate that these provisions would increase gas production by 0.5 to 0.6 Bcf per year, resulting in cost savings of about $2-3 million per year (using 7 percent and 3 percent discount rates). This would also reduce methane emissions by 11,500 to 14,500 tpy, producing monetized benefits of $13 million per year in 2017-2019, $16-18 million per year in 2020-2024, and $21-22 million in 2025 and 2026. Overall, under this scenario, these provisions are estimated to produce net benefits of $3-15 million per year (considering the present value of costs and cost savings using a 7 percent discount rate) or net benefits of $3-13 million per year (considering the present value of costs and cost savings using a 3 percent discount rate), and reduce VOC emissions by 9,600 to 12,200 tpy.
Finally, the BLM proposes to revise the regulations at 43 CFR 3103.3-1, which govern royalty rates applicable to onshore oil and gas leases, to make the rule text parallel to the statutory text, respond to findings and recommendations in audits from the GAO, and eliminate unnecessary provisions in the existing regulations.
The proposed revisions would do three principal things: (1) Make clear that the royalty rate on all existing leases would remain at the rate prescribed in the lease or in regulations applicable at the time of lease issuance; (2) Specify the fixed, statutory rate of 12.5 percent
Overall, assuming that the EPA finalizes its concurrent 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that this proposed rule will pose costs ranging from $125-161 million per year (using a 7 percent discount rate) or $117-$134 million per year (using a 3 percent discount rate) over the next 10 years.
If, for analytical purposes, we assume that EPA does not finalize its concurrent 40 CFR part 60 subpart OOOOa rulemaking, these requirements would affect more sources and the costs would be somewhat higher. Under that scenario, the BLM estimates that this rule will pose costs ranging from $139-174 million per year (using a 7 percent discount rate) or $131-147 million per year (using a 3 percent discount rate) over the next 10 years.
In some areas, operators have already undertaken, or plan to undertake, voluntary actions to address gas losses. To the extent that operators are already in compliance with the requirements of this proposed rule, the above estimates overstate the likely impacts of the rule.
We expect that cost impacts on individual operators would be small, even for businesses with less than 500 employees. In the RIA, we estimate that average costs for a representative small operator would increase by about $31,300-37,500, which would result in an average reduction in profit margin of 0.087-0.104 percentage points in 2020.
We measure the benefits of the rule as the cost savings that the industry would receive from the recovery and sale of natural gas and the environmental benefits of reducing the amount of methane (a potent GHG) and other air pollutants released into the atmosphere. As with the estimated costs, we expect benefits on an annual basis. The estimated benefits of the rule also depend on whether the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking. Assuming that rule is in effect, the BLM estimates that this rule would result in monetized benefits of $255-329 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings, and using model averages of the social cost of methane with a 3 percent discount rate) or $255-357 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings, and using model averages of the social cost of methane with a 3 percent discount rate).
If, for purposes of analysis, we assume that EPA does not finalize its 40 CFR part 60 subpart OOOOa rulemaking, we estimate that this proposed rule would result in monetized benefits of $270-354 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate) or $270-384 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate).
Adoption of the proposed rule would also have numerous ancillary benefits. These include improved quality of life for nearby residents, who note that flares are noisy and unsightly at night; reduced release of VOCs, including benzene and other hazardous air pollutants; and reduced production of nitrogen oxides (NO
Overall, the BLM estimates that the benefits of this rule outweigh its costs by a significant margin. The BLM expects net benefits ranging from $115-188 million per year (using a 7 percent discount rate) or $138-232 million per year (using a 3 percent discount rate). Specifically, assuming a 7 percent discount rate, we estimate the following annual net benefits:
• $115-130 million per year from 2017-2019;
• $155-156 million per year from 2020-2024; and
• $187-188 million per year from 2025-2026.
Assuming a 3 percent discount rate, we estimate the annual net benefits would be:
• $138-151 million per year from 2017-2019;
• $192-196 million per year from 2020-2024; and
• $231-232 million per year from 2025-2026.
If, for purposes of analysis, we assume that the EPA does not finalize the 40 CFR part 60 subpart OOOOa rulemaking, we estimate the net benefits of this proposed rule would be somewhat higher, ranging from $119-203 million per year (costs and costs savings calculated using a 7 percent discount rate) or $139-245 million per year (costs and costs savings calculated using a 3 percent discount rate).
The proposed rule has a number of requirements that are expected to influence the production of natural gas, NGLs, and crude oil from onshore Federal and Indian oil and gas leases.
If 40 CFR part 60 subpart OOOOa is finalized, we estimate the following incremental changes in production, noting the representative share of the total U.S. production in 2014 for context. We estimate additional natural gas production, ranging from 11.7-14.5 Bcf per year (representing 0.04-0.05 percent of the total U.S. production in 2014), the productive use of an additional 29-41 Bcf of natural gas, which we estimate would be used to generate 36-51 million gallons of NGL per year (representing 0.08-0.11 percent of the total U.S. production), and a reduction in crude oil production ranging from 0.6-3.2 million bbl per year (representing 0.02-0.10 percent of the total U.S. production). We also expect 0.5 Bcf of gas to be combusted on-site that would have otherwise been vented. Combined, the capture or combustion of gas represents 44-46 percent of the volume vented in 2013 and the capture and/or productive use of the gas 41-60 percent of the volume flared in 2013.
If 40 CFR part 60 subpart OOOOa is not finalized, we estimate additional natural gas production ranging from 12-15 Bcf per year (representing 0.04-0.06 percent of the total U.S. production), the productive use of an additional 29-41 Bcf of natural gas, which we estimate would be used to generate 36-51 million gallons of NGL per year (representing 0.08-0.11 percent of the total U.S. production), and a reduction in crude oil production ranging from 0.6-3.2 million bbl per year (representing 0.02-0.10 percent of the total U.S. production). Separate from the volumes listed above, we also expect 1 Bcf of gas to be combusted on-site that would have otherwise been vented. Combined, the capture or combustion of gas represents 49-52 percent of the volume vented in 2013 and the capture and/or productive use of gas represents 41-60 percent of the volume flared in 2013.
Since the relative changes in production are expected to be small, we do not expect that the proposed rule would significantly impact the price, supply, or distribution of energy.
Assuming the EPA 40 CFR part 60 subpart OOOOa rulemaking is finalized, we estimate that this proposed rule would produce additional royalties of $9-11 million per year (discounted at 7 percent) or $10-16 million per year (discounted at 3 percent).
If you wish to comment on the proposed rule, you may submit your comments by any one of several methods specified (see
Please make your comments as specific as possible by confining them to issues for which comments are sought in this notice, and explain the basis for your comments. The comments and recommendations that will be most useful and likely to influence agency decisions are:
1. Those that are supported by quantitative information or studies; and
2. Those that include citations to, and analyses of, the applicable laws and regulations.
The BLM is not obligated to consider or include in the Administrative Record for the rule comments received after the close of the comment period (see
Comments, including names and street addresses of respondents, will be available for public review at the address listed under
The BLM's onshore oil and gas management program is a major contributor to our nation's oil and gas production. The BLM manages more than 245 million acres of land and 700 million acres of subsurface estate, comprising nearly a third of the nation's mineral estate. Domestic production from over 100,000 Federal onshore oil and gas wells accounts for 11 percent of the Nation's natural gas supply and 5 percent of its oil. In FY 2014, the ONRR reported that operators produced 204.6 MMbbl of oil, 2 Tcf of natural gas, and 3.1 billion gallons of NGLs from onshore Federal and Indian oil and gas leases. The production value of this oil and gas exceeded $27.2 billion and generated approximately $3.1 billion in royalties.
Over the past decade, the United States has experienced a dramatic increase in natural gas and oil production due to technological advances, such as hydraulic fracturing combined with directional drilling. This boost in production has brought many benefits in the form of expanded and more secure domestic supplies, lower prices, increased economic activity, and greater royalty revenues for Federal, State, and tribal governments.
At the same time, the American public has not benefited from the full potential of this increased production, as it has been accompanied by significant and growing quantities of wasted natural gas. Between 2009 and 2014, operators on BLM-administered leases wasted enough natural gas to serve 5.1 million homes for 1 year, according to data reported to ONRR.
A sizeable quantity of natural gas is flared or vented in the course of exploration, development, and production activities. Commonly used well pad production equipment, such as pneumatic controllers, are designed to function by venting natural gas. Leaks and other unintentional releases across oil and gas operations account for additional waste. As discussed in the RIA, we estimate that in 2013, about 98 Bcf of natural gas was vented, flared, or leaked from oil and gas production on BLM-administered leases.
This proposed rule aims to reduce wasteful venting, flaring, and leaks of natural gas from oil and natural gas production activities on onshore Federal and Indian leases. The rule would update the BLM's existing requirements
The BLM expects that these regulations would benefit the public by reducing waste of a public resource, improving production accountability, increasing natural gas supplies, and increasing royalties received by Federal, State, and tribal governments. In addition, reducing venting and flaring would reduce impacts on local communities and the environment by reducing emissions of air pollutants that contribute to smog, particulate pollution, and climate change.
Natural gas is a valuable resource that plays a significant role in the U.S. economy and is critical to our energy and national security. Gas that is flared, vented, or leaked into the atmosphere from production on BLM-administered leases is a lost public or tribal resource that is not available for productive use.
In addition, most of the lost gas is not currently subject to royalties, which compensate the public for the removal of publicly owned resources and help fund activities of States, localities, tribes and the Federal Government. State governments receive roughly half of the 12.5 percent royalty that the Federal Government typically collects from onshore oil and gas lessees. The BLM estimates that if captured, the gas presently lost from BLM-administered leases would provide an additional $49 million in royalties each year to the Federal Government, States, and tribes.
This waste of gas through flaring can affect the quality of life for nearby residents, who note that flares are noisy and unsightly at night. Venting, flaring, and leaks of gas also contribute to local, regional, and global air pollution. VOCs and hazardous air pollutants (components of the gas, such as benzene, toluene, ethylbenzene, and xylene) are released into the atmosphere when natural gas is released through venting, flaring, or incomplete combustion at a flare. VOCs combine with sunlight and NO
Venting and leaks of natural gas in the oil and gas production process also contribute to climate change. Natural gas is primarily composed of methane, which is a potent GHG. Measured over a 100-year time-frame, methane results in more than 20 times more warming than CO
The purpose of this proposed rule is to establish a comprehensive framework to give operators on Federal and tribal leases clear direction to minimize waste and losses of natural gas. This proposed rule is necessary because the BLM's existing requirements on venting and flaring are more than 3 decades old, do not reflect technological advances and current scientific understanding, have failed to deter rising losses of gas, fail in some respects to provide clear guidance to BLM staff and oil and gas operators, and do not address leaks from existing and new infrastructure.
This proposed rule would implement statutory directives to avoid waste of oil and gas resources. It would supplement the BLM's regulations contained in 43 CFR 3162.5 and 3162.7, to address prevention of waste of produced natural gas, use of produced oil and gas on a royalty-free basis, and record keeping requirements. It would also update and replace NTL-4A,
The BLM recognizes the importance of ensuring that our requirements do not subject operators to conflicting or redundant requirements. In 2012, the EPA adopted air pollution regulations for certain activities in the oil and gas production sector, and the EPA has recently proposed further regulations in that area, which would have the effect of reducing loss of gas. In addition, in response to growing concerns about venting, flaring, and leakage of gas, several States have adopted or are considering regulations to address these issues. The EPA regulations focus largely on new sources, however, and they are directed at pollution reduction, not waste prevention, so they do not address all opportunities to reduce waste. Similarly, none of the States has established a comprehensive set of requirements addressing all of the sources of lost gas that we are considering here, and many States have minimal requirements in this area. We are committed to working closely with State and tribal governments to ensure that the BLM requirements are coordinated with State and tribal requirements to the extent possible. The BLM requirements would not supersede equally effective or more stringent State and tribal requirements. We are also working closely with the EPA to coordinate our requirements, so that operators are not faced with conflicting or duplicative Federal mandates.
Over several months of last year, the BLM conducted a series of forums to consult with tribal governments and solicit stakeholder views to inform the development of this proposed rule. We held public meetings in Denver, Colorado (March 19, 2014), Albuquerque, New Mexico (May 7,
As part of our outreach efforts, the BLM accepted informal comments generated as a result of the public/tribal outreach sessions through May 30, 2014. A total of 29 unique comments were received: 12 from the oil and gas industry and trade associations, 6 from NGOs representing 37 organizations, 2 from government officials or elected representatives and 9 from private citizens. Two hundred and sixty comments from private citizens were part of an email campaign.
In addition, the BLM has conducted outreach to States with extensive oil and gas production on BLM-administered leases. We have carefully reviewed State regulations and guidance, and we have contacted State regulatory bodies that oversee aspects of oil and gas production to discuss their requirements and practices. We look forward to continued close interaction with State and tribal regulators.
The proposed rule reflects input gathered from the public meetings, comments, and discussions with States and tribes.
Venting, flaring, and royalty-free uses of oil and natural gas on BLM-administered leases are currently governed by NTL-4A, which was issued by the U.S. Geological Survey on December 27, 1979, before the BLM assumed oversight responsibility for onshore oil and gas development and production. NTL-4A prohibits venting or flaring of gas well gas, and it prohibits venting or flaring of oil well gas unless approved in writing by the “Supervisor.”
The Supervisor may approve an application for the venting or flaring of oil well gas if justified either by the submittal of (1) an evaluation report supported by engineering, geologic, and economic data which demonstrates to the satisfaction of the Supervisor that the expenditures necessary to market or beneficially use such gas are not economically justified and that conservation of the gas, if required, would lead to the premature abandonment of recoverable oil reserves and ultimately to a greater loss of equivalent energy than would be recovered if the venting or flaring were permitted to continue or (2) an action plan that will eliminate venting or flaring of the gas within 1 year from the date of application.
In addition, NTL-4A specifies the circumstances under which an operator owes royalties on oil and gas that is lost from a lease. It provides that gas which is “avoidably lost” is subject to royalties. It defines “avoidably lost” production as produced gas that is vented or flared without the “prior authorization, approval, ratification, or acceptance of the Supervisor,” or lost due to: (1) Negligence; (2) Failure to comply with lease terms, the operating plan, orders or regulations; or (3) “(T)he failure of the lessee or operator to take all reasonable measures to prevent and/or to control the loss.”
NTL-4A III. authorizes royalty-free venting or flaring of gas “on a short-term basis” without the need for approval under specified circumstances, including during: (1) Emergencies; (2) Well purging and evaluation tests; and (3) Initial production tests.
Over the past 36 years since NTL-4A was issued, technologies and practices for oil and gas production have advanced considerably. The development of modern hydraulic fracturing and horizontal drilling techniques has been especially significant. We also now have better technologies for capturing and using gas on-site, detecting leaks, powering equipment, controlling vapors from storage vessels, removing liquids from gas wells, and many other aspects of production. Not surprisingly, NTL-4A neither reflects today's best practices and advanced technologies, nor is particularly effective in requiring their use to avoid waste. In addition, much of NTL-4A relies on broad, generalized directives. As these have been implemented in the decades since NTL-4A was issued, there has been ambiguity and variation regarding the circumstances under which venting or flaring requires prior approval, the circumstances under which venting or flaring is approved, and the circumstances under which royalties are paid on vented and flared gas. There is also some ambiguity regarding what properly constitutes royalty-free on-site use. All of these factors indicate the need to update NTL-4A.
NTL-4A also includes a provision for assessing the full value of avoidably lost gas and gas that is vented or flared without required approval.
NTL-4A's “full value” policy has not been enforced since FOGRMA's enactment. The proposed rule would comply with FOGRMA Section 308 and require payment of royalty, rather than full value, on all oil and gas that is avoidably lost.
With this proposed rule, the BLM aims to update the NTL-4A requirements for venting, flaring, and royalty-free uses of oil and natural gas on BLM-administered leases. The BLM's general authority to issue this proposed regulation derives from various statutes applicable to onshore Federal lands and minerals and Indian tribal and allotted lands, principally the MLA, MLAAL, FOGRMA, FLPMA, IMDA, IMLA, and the Act of March 3, 1909.
The MLA rests on the fundamental principle that the public should benefit from mineral production on public lands.
In FLPMA, Congress declared it to be the policy of the United States that the BLM should manage the public lands “in a manner that will protect the quality of scientific, scenic, historical, ecological, environmental, air and atmospheric, water resources, and archeological values; . . . preserve and protect certain public lands in their natural condition; . . . provide food and habitat for fish and wildlife; and . . . provide for outdoor recreation and human occupancy and use.”
The proposed rule would supplement BLM onshore lease operations regulations found at part 3160 of Title 43 of the Code of Federal Regulations (CFR). The rule would apply to all BLM-managed leases. The proposed rule would also apply to business agreements entered into by tribes (other than Osage Tribe) and agreements under the IMDA, as consistent with those agreements and with principles of Federal Indian law. Oil and gas agreements entered into under the IMDA may or may not provide for a royalty; if they do, that royalty may or may not be expressed as a percentage of the production “removed or sold from the lease.”
The BLM's authority to require royalty payments derives from the above-quoted provision in the MLA: “A lease shall be conditioned upon the payment of a royalty at a rate of not less than 12.5 percent in amount or value of the
The proposed rule does not use the terms “beneficial purpose” and “beneficial use,” which are used in NTL-4A. Over the years, those terms appear to have been applied inconsistently within the BLM, creating confusion for some in the industry regarding when production may be used royalty-free. Instead of referencing beneficial purposes or use, the proposed rule would directly address the royalty-free treatment of various uses of lease production, and would identify the situations in which prior written BLM approval would be required for royalty-free treatment.
The BLM, through NTL-4A, has long read the MLA to exempt from royalty payments production that is “unavoidably lost” in the course of production.
Several oversight reviews have raised concerns about waste of gas, found that the BLM's existing requirements regarding venting and flaring are insufficient, and have identified concerns about royalty-free use of gas. They recommended that the BLM update its regulations and guidance on royalty-free use and waste prevention. These include reviews by the Subcommittee on Royalty Management of the Royalty Policy Committee (RPC), which is a Federal advisory committee to the Department of the Interior; the Inspector General of the Department of the Interior; and the GAO.
The RPC's December 2007 report entitled,
In October 2010, the GAO issued a report entitled,
The GAO found that “around 40 percent of natural gas estimated to be vented and flared on onshore Federal leases could be economically captured with currently available control technologies.”
The GAO recommended that “to help reduce venting and flaring of gas by addressing limitations” in the regulations, the “BLM should revise its guidance to operators to make it clear that technologies should be used where they can economically capture sources of vented and flared gas, including gas from liquid unloading, well completions, pneumatic valves, and glycol dehydrators.”
In addition, multiple public advocacy organizations have recently raised concerns about the waste of gas in oil and gas production operations, and recent State regulatory actions to reduce venting and flaring indicate that some States share these concerns as well.
While concerns have been growing over rising quantities of lost gas, there is no single definitive estimate on the volume of these losses from Federal and Indian leases. One relevant source of information for estimating the volumes of waste is the Oil and Gas Operations Report Part B (OGOR-B) that producers from BLM-administered leases file each month with ONRR to report quantities of gas removed from their leases. Another key source of information is the EPA Inventory of Greenhouse Gas Emissions and Sinks (2015) (“EPA GHG Inventory”), which is an annual report that estimates the total national GHG emissions and removals associated with human activities across the United States. Additional information is drawn from the EPA Greenhouse Gas Reporting Program (GHGRP), which collects GHG data from large emitting facilities, suppliers of fossil fuels and industrial gases that result in GHG emissions when used. Additional emissions quantification data was presented by ICF in a publication entitled,
The data collected by ONRR includes operators' estimates of gas vented and flared-during production from each Federal and Indian lease. These data do not include any estimates of natural gas lost through leaks, or from routine operation of pneumatic devices, storage vessels, compressors, or glycol dehydrators (equipment that circulates the chemical glycol in gas to absorb moisture). In addition, the GAO found that there is variation across BLM offices as to whether operators must report certain other types of natural gas losses on their OGOR-Bs. Specifically, operators varied in whether they included quantities of vented or flared gas where the BLM had authorized the venting or flaring or where the quantities were under the BLM's permissible limits. Operators are also not always required to meter the quantities of vented or flared gas reported on their OGOR-Bs. Instead they may use BLM-approved methods to estimate the quantities to be reported. So while the ONRR data are highly relevant, they provide information about a subset of gas wasted and there is some uncertainty regarding the accuracy of the estimates the data do include. In reviewing these data, the GAO found that they “likely underestimate venting and flaring because they do not account for all sources of lost gas.”
For purposes of this proposed rule, ONRR provided the BLM with 6 years of vented and flared volumes reported on the OGOR-Bs. The data analyzed included gas flared and vented from both oil wells and gas wells from 2009 through 2014. During this period, operators reported that they vented or flared a total of 375 Bcf of natural gas, or about 2.6 percent of the 14.6 Tcf of natural gas that was produced from BLM-administered leases from 2009 through 2014. This is enough natural gas to supply about 5 million households—or every household in the States of Colorado, Montana, New Mexico, Utah, and Wyoming—for 1 year.
Data in the EPA GHG Inventory can be used to calculate a more complete estimate of gas losses from venting and leaks from BLM-administered leases, which is discussed in more detail in the Regulatory Impact Analysis (RIA) for this rule. Using data from the GHG Inventory, we estimate that about 167 Bcf of natural gas was released or vented to the atmosphere from all U.S. onshore oil and gas leases in 2013, the most recent year for which estimates are currently available. In that year, production from Federal and Indian leases accounted for 12.7 percent of the U.S. natural gas production and 7.43 percent of the U.S. crude oil production.
In addition, the ONRR data indicate that operators reported flaring 76 Bcf of natural gas from BLM-administered leases in 2013 (the most recent year for which data are available). Of this, ONRR estimates that about 44 Bcf was gas from the Federal and Indian mineral estate (as opposed to gas from State or private mineral estates that is being extracted through a well that is producing from a mix of Federal, Indian, State or private mineral estates).
Thus, for purposes of this proposal, our best estimate is that 98 Bcf of natural gas was vented, leaked, or flared from BLM-administered leases in 2013,
Based on available data, the problem of natural gas loss on BLM-administered leases is also growing. The total amounts of annual reported flaring from Federal and Indian leases increased by 109 percent from 2009 through 2013.
Another indicator of the increase of flaring on Federal and Indian lands is the increase of applications to vent or flare received by the BLM. In 2005, the BLM received just 50 applications to vent or flare gas. In 2011, the BLM received 622 applications, and this doubled again within 3 years to 1,248 applications in 2014. BLM field offices indicate that most of the additional applications were for flaring in New Mexico, Montana, the Dakotas, and, to a lesser extent, Wyoming.
In addition to considering the quantity of gas that is lost now, it is also important to consider the potential future quantities of lost gas, and to evaluate the future sources of such losses. One source of information on this question is a study by ICF entitled,
The BLM developed the emissions estimates discussed in the preamble and RIA using the best data available at the time. Some of the data produced by EPA and ONRR, such as the EPA estimates of the quantities of gas lost through leaks, and emergency releases reported to ONRR by the operators, rely on emissions factors, which have been developed by the EPA. These emissions factors are usually based on representative measured data and are applied to activity data to calculate estimated emissions. The ONRR relies primarily on self-reporting by industry, subject to agency audits.
Annually, EPA reviews new information as it becomes available, and the GHG Inventory continues to be refined to reflect new information available. For example, EPA notes the availability of new data in its GHG Inventory, including data and information that are becoming available through EPA's GHGRP and external studies, allowing EPA to re-evaluate and make updates to GHG Inventory data, as applicable.
Several recently completed academic studies aim to improve our understanding of the quantity of natural gas and petroleum system emissions, and more such studies are underway. In general, there are two major types of studies related to oil and gas GHG data: So-called “bottom up” studies that focus on measurement or quantification of emissions from specific activities, processes, and equipment (
An article published last year in the peer-reviewed journal
Beginning in 2012, the Environmental Defense Fund began working with about 100 universities, research institutions and companies on a multi-pronged scientific research effort to develop a clearer picture of methane losses across the U.S. natural gas supply chain. Several studies from this effort, in addition to the NOAA and
For example, researchers at the University of Texas, Austin, in Phase 1 of their production studies, published in September 2013, found that methane emissions from equipment leaks and pneumatic devices were larger than previously thought.
A February 2015 study from Colorado State University, entitled
On the other hand, another recent study found that methane measurements taken by aircraft in some natural gas production basins track well with the EPA's GHG Inventory estimates.
Most recently, a new study by Zavala et al., published in the
The BLM expects that additional studies will use bottom-up and top-down data comparisons to continue to refine emissions estimates for these sources. The presence, distribution, and effect of super-emitters, which are often defined as sources with exceptionally high emissions as compared to similar sources (essentially malfunctioning equipment), is also being further studied. Overall, these studies and alternative sources of data suggest that the BLM's estimates of lost gas likely underestimate, and potentially substantially underestimate, the extent of the problem.
In developing the proposed rule, we have consulted with State regulators and reviewed State requirements related to waste of oil and gas resources. Like the MLA, most State laws and regulations prohibit or encourage prevention of waste of these resources. But specific State requirements, and the outcomes they produce, vary widely. This variability reinforces the need for this rule to update standards for oil and gas operations on Federal and Indian lands. In developing the proposed rule, we also looked to some of the most effective State approaches as models. In particular, we have drawn on new requirements recently adopted by Colorado and North Dakota to address rising rates of flaring, resource losses, and other impacts. Below we summarize how several States have approached these issues.
The State of Alaska adopted regulations in the 1970s to address high rates of flaring.
The State of Colorado has reduced venting and flaring through air quality regulations directed at emissions of hydrocarbons and VOCs from the oil and natural gas industry.
In addition to requiring green completions, Colorado's rules: Establish requirements for pneumatic controllers;
The State of Montana has had limits on venting and flaring in place since the 1970s. Produced gas vented to the atmosphere at a rate exceeding 20 Mcf per day that continues for more than 72 hours must be burned.
North Dakota has experienced a rapid increase in oil production in recent years. A byproduct of this development is more natural gas being produced than can be processed and transported to market through existing pipeline infrastructure. Without access to a market, much of the associated natural gas continues to be flared.
In March 2013, the North Dakota Industrial Commission adopted a policy to reduce flaring, and it followed this with an enforceable order adopted in July 2014 and modified in September 2015.
North Dakota's policy includes additional requirements intended to help operators reach the targets.
The policy provides for oil production to be restricted from wells where the operator does not meet the flaring reduction targets.
In August 2013, the Pennsylvania Department of Environmental Protection issued guidance that exempted from certain air quality permitting requirements oil and gas exploration, development, and production facilities and associated equipment and operations that implemented the following: An LDAR program consistent with relevant EPA regulations; VOC emission controls on all storage tanks; a 2.7 tpy limit on VOC emissions from all facility sources; certain limitations on flaring activities; and hourly, daily, seasonal, and annual limits on NOx emissions.
The Utah Department of Environmental Quality issued a General Approval Order on June 5, 2014, that applies to new and modified oil and gas well sites and tank batteries. Among other provisions, this order requires pneumatic controllers to be low bleed or route the emissions to a flare or capture device; pneumatic pumps route emissions to a flare or capture device; and requires operators to inspect for leaks at least annually, and more frequently for sources with greater throughput levels.
The Wyoming Department of Environmental Quality adopted regulations in June 2015, to reduce emissions of VOCs from storage vessels, pneumatic controllers, pneumatic pumps, glycol dehydrators, and leaks in the Upper Green River Basin nonattainment area.
The oil and gas industry has also recognized concerns about the rising quantities of flared and vented gas, and has begun to take voluntary steps to reduce gas losses. For example, oil and gas companies developed the technologies for green completions.
Many of these efforts have been initiated by companies participating in Natural Gas STAR, a voluntary EPA-industry partnership program that encourages oil and natural gas companies to adopt cost-effective technologies and practices that improve operational efficiency and reduce methane emissions. Twenty-six companies in the production sector currently participate in Natural Gas STAR. Partners in this program have
To further encourage emissions reductions from the oil and gas sector, the EPA announced, in July 2015, a voluntary program called the Natural Gas STAR Methane Challenge, in which companies would make ambitious commitments to reduce methane emissions and would track their progress in achieving those reductions.
In addition, six oil and gas companies have joined together to form the One Future Coalition, which aims to “(e)nhance the energy delivery efficiency of the natural gas supply chain by limiting energy waste and by achieving a methane `leak/loss rate' of no more than one percent.”
While EPA does not regulate waste of oil and gas resources, certain air pollution regulations applicable to the oil and gas production sector have the co-benefit of also reducing waste of natural gas. Because the air pollutants regulated by EPA are contained in natural gas, many of the control options for reducing emissions operate by limiting the release (and hence loss) of natural gas. To the extent that EPA rules under the Clean Air Act address some aspects of the waste issue, the BLM intends to coordinate its requirements with the EPA as far as possible, to ensure that industry is not burdened by duplicative or conflicting requirements. The EPA rules will include both standards that EPA adopted in 2012, which are largely focused on natural gas wells and infrastructure, and the 40 CFR part 60 subpart OOOOa rulemaking, which addresses additional categories of new and modified sources in the oil and gas production sector.
In 2012, EPA adopted NSPS to limit the release of VOCs from new and modified hydraulically-fractured natural gas wells, certain new or modified sources located at well sites, natural gas processing plants, or natural gas gathering and boosting stations.
The 2012 standards also require operators to use certain types of new and modified equipment at natural gas processing plants and gathering and boosting stations. The standards limit VOC emissions from centrifugal compressors and establish maintenance requirements for reciprocating compressors.
On September 18, 2015, EPA published a notice of proposed rulemaking that proposes NSPS standards to be codified as 40 CFR part 60 subpart OOOOa.
In addition, the EPA proposed to issue Control Technique Guidelines (CTGs), which States could adopt in nonattainment areas to reduce methane emissions from
While the proposed EPA standards are expected to reduce methane emissions from certain new and modified oil and gas production facilities, they would not be sufficient to meet the goals of BLM's proposed rule for several reasons. First, the proposed EPA regulations do not include any provisions to reduce flaring of associated gas during normal production operations. Second, even with respect to the natural gas waste from venting, the EPA regulations would apply only to new and modified sources, whereas this proposal would reach existing sources as well. In States that choose to adopt the CTGs, those guidelines would apply to existing sources, but the guidelines are designed to reduce emissions in nonattainment
Similarly, of the States with extensive oil and gas operations on BLM-administered leases, only one has comprehensive requirements to reduce flaring, and only one has comprehensive statewide requirements to control losses from venting and leaks. Moreover, State regulations do not apply to BLM-administered oil and gas leases on Indian lands, and States do not have a statutory mandate to reduce waste of Federal oil and gas.
In addition, the BLM has regulated oil and gas operations on Federal and Indian leases for decades to prevent waste, conserve resources, and protect public lands. The BLM has the responsibility and experience to ensure that these valuable public resources are extracted in a safe manner, while minimizing harm to local communities and the environment and ensuring fair returns to Federal taxpayers and tribes. We have existing requirements that are intended to serve these purposes, but NTL-4A is over 3 decades old and is no longer adequate in meeting these goals. Thus, the proposed rule would update NTL-4A, and would do so in coordination with the concurrent EPA rulemaking. In addition, the proposed rule would make provision for State and tribal programs that address flaring or venting.
The proposed rule would require operators to limit waste of gas through flaring and venting, clarify the situations in which flared gas would be subject to royalties, conform the royalty terms applicable to competitive leases with the corresponding statutory language, and clarify the on-site uses of gas that are exempt from royalties. In addition, the BLM is proposing to require operators to record and report information related to venting and flaring of gas, and is taking comment on how best to make this information more available to the public. This section of the preamble also includes a discussion of how today's proposal relates to the planning process for lands subject to BLM administration, although this rule would not make any regulatory changes to the planning process itself.
The BLM has identified several key points in the production process where waste-prevention actions would be most effective and least costly. Specifically, we propose to focus on reducing waste from the following: Flaring of associated gas from producing oil wells; gas leaks from equipment and facilities located at the well site, as well as from compressors located on the lease; operation of high-bleed pneumatic controllers and certain pneumatic pumps; gas emissions from storage vessels; well maintenance and liquids unloading; and well drilling and completions. Based on the available data regarding methane emissions and the numbers and types of sources of gas losses from Federal and Indian leases, we believe that these aspects of the production process offer the best opportunities for reducing waste.
To the extent that EPA completes regulations that would have the effect of reducing waste from these sources, the BLM proposes to take EPA's requirements into account in finalizing this proposed rule to avoid conflict or burdensome duplication.
In addition, the BLM requests public comments on the scope of this proposed rule, including whether there are other aspects of the production process that might provide sufficient opportunities for economical and cost-effective waste reduction to warrant inclusion in this regulation. We also request comment on whether we could achieve additional economical and cost-effective waste reduction from any of the sources of waste that we are addressing here. In addition, we request comment on the cost-effectiveness of the changes we are proposing to each aspect of the production process, taking into account the full range of private and public benefits achieved through waste reduction. We also request comment on how we could lower costs of the measures that we are proposing here.
As discussed earlier in Section II.H. of this preamble, operators currently vent gas under some circumstances, and they also flare large quantities of natural gas that is produced at oil wells (commonly called “associated gas” or “casinghead gas”). Operators have an economic incentive to capture and sell the flared gas, or to use it on-site. Nonetheless, substantial flaring occurs under a variety of circumstances.
BLM analysis of ONRR data shows that operators reported venting about 22 Bcf and flaring at least 76 Bcf of natural gas from BLM-administered leases in 2013 (with about 44 Bcf estimated to be Federal and Indian minerals).
According to ONRR data, 91 percent of flared oil-well gas from BLM-administered leases occurred in three States: North Dakota, South Dakota, and New Mexico. In 2013, the volumes of flared oil-well gas from BLM-administered leases in these States were about 42 Bcf, 15 Bcf, and 8 Bcf, respectively.
The primary means to avoid flaring of associated gas from oil wells is to capture, transport, and process that gas for sale, using the same technologies that are used for natural gas wells. While industry continues to reduce the cost and improve the reliability of this technology, it is long-established and well understood. The capture and sale of associated gas can pay for itself where there is sufficient gas production relative to costs of connecting to or expanding existing infrastructure. The costs of installing equipment and pipelines for capture and transport can range from $400,000 to $1 million per mile for a 4-inch natural gas pipeline.
In addition, the recent increase in flaring has encouraged entrepreneurs to develop new technologies and applications designed to capture smaller amounts of gas and put them to productive uses where building a pipeline to connect to the market is impractical. Companies are beginning to experiment with and deploy several technologies as potential alternatives to the traditional pipeline systems that capture associated gas. These include: Separating out NGLs, which are often quite valuable, and trucking them off location; using the gas to run micro-turbines to generate power; and using small integrated gas compressors to convert the gas into CNG that can be used on-site or trucked off location for use as transportation fuel or conversion to chemicals. In addition, there are other promising and innovative approaches that are either in development or in the earlier stages of deployment.
Natural gas contains hydrocarbons that can exist in liquid phase without being in a high pressure or low temperature environment. These are referred to as NGLs. Higher NGL concentrations in a gas stream reflect higher heating (Btu) value and a higher combined commodity value when the NGLs are separated from the remaining gas stream. Although NGLs are typically stripped and fractionated into their various components (
Facilities to condense natural gas into LNG are more cost-effective at locations with large amounts of flaring, as relatively larger quantities of gas are needed to offset the cost of the LNG equipment. The surface area of well sites may need to be expanded to accommodate truck traffic and product storage needs. Also, because associated gas production drops off quickly at hydraulically fractured oil wells, LNG recovery is more likely to be cost-effective if it is implemented when production starts.
Micro-turbines that generate electricity typically require preprocessing of the associated gas to minimize equipment maintenance issues. Generating electricity can work well if it is paired with NGL recovery, as the NGL residue gas stream is well suited as fuel for the generators. However, scaling the generators to the electricity demand that could be used locally on the well pad complicates their use. The generators may produce more electricity than is needed on site, but it may be too costly to connect to the electric grid from a remote location, as would be necessary to put the excess electricity to productive use. The cost of connecting to the electric grid depends, among other things, on the distance of the operation from the nearest electrical distribution lines. Moreover, the electricity produced for use on site would be viewed as beneficial use, and therefore the gas used to generate the electricity would be royalty free. If the electricity produced by a micro-turbine is sold to the grid, however, it would not be beneficial use and the gas used to generate the electricity would not be royalty free.
The CNG alternative technologies show considerable promise in effectively transporting associated gas to a centrally located processing plant while removing the higher value NGLs for other productive uses. Well sites may need to be expanded to accommodate truck traffic and storage needs, but not to the extent needed under the LNG option. The on-site equipment for CNG is smaller than for LNG, and the size of the CNG operation can also be more easily adjusted to meet the associated gas decline over the life of the well. However, limitations on the amount and rate of natural gas capture/compression on-site can limit applicability of this technology. Breakthroughs in compression technology are increasing the range of viable sites where CNG would be the preferred alternative technology. This technology could become sufficiently attractive to reduce flaring to near zero rates, according to companies offering these services. While these newer on-site technologies may not be suitable in all situations, in many cases they could provide a profitable alternative to using traditional pipelines for capture and sale as a way to reduce waste, and operators should consider these approaches in assessing the opportunities to reduce waste from venting and flaring.
In addition, there are a number of technologies that can improve the efficiency of flares and ensure that a flare combusts as large a proportion of the gas as possible. In particular, automatic igniters can be used to ensure that the flare is relit if the gas flow stops intermittently.
In considering how to reduce flaring, it is important to recognize that gas is flared under a variety of circumstances, some of which are unplanned or unavoidable in the course of normal oil and gas production. Emergencies can occur through an unforeseen event, such as a weather-related incident or an accident that damages equipment resulting in the loss of gas.
In other cases, operators flare gas because they, and the midstream processing companies that commonly build and operate gas gathering and processing infrastructure, do not yet know whether there will be a sufficient quantity of gas available to capture. Thus, companies have not yet invested in building gathering lines and processing plants to capture and sell gas for commercial use. For example, the well may be an exploration or wildcat well in a new field, far from existing capture infrastructure, and it is not yet known whether the field will produce much gas. Similarly, in some fields, the overall quantity of gas produced across multiple wells is sufficiently small that, even cumulatively, the wells do not produce enough natural gas to offset the costs of building pipeline infrastructure. While flaring in these situations has generally been considered unavoidable, the BLM believes this assumption is challenged by the development of the alternative capture technologies described above, which calls into question whether it remains reasonable to assume that there are no alternatives to flaring when a field produces only a small quantity of natural gas. The BLM requests comment on this point. In many instances, however, the decision to flare large quantities of associated gas is driven by an operator's economic calculation that the value of immediately producing the oil outweighs the value of the natural gas that could be captured. In addition,
Two circumstances that result in substantial ongoing or intermittent flaring of associated gas on BLM-administered leases are: (1) Flaring in areas with existing capture infrastructure, but where the rate of new-well construction is outpacing the infrastructure capacity; and (2) Flaring in areas where capture and processing infrastructure has not yet been built out. While the majority of associated gas flaring on BLM-administered leases occurs in the first situation, our proposed approach to reducing flaring addresses both circumstances.
The first situation occurs in areas that have extensive natural-gas gathering lines, which are connected to pipelines leading to processing plants. However, in many areas in recent years the rate of oil development and the rapid rise in quantities of associated gas have overwhelmed the capacity of the gathering lines and/or processing plants. New wells (especially in shale formations) often start out producing a relatively large amount of oil and/or gas at relatively high pressures, which then declines rapidly over time. Thus, each time a new oil well with associated gas connected to the gathering system starts production, it may increase the pressures on the system above the pressures generated by existing producing wells, pushing those wells off the gathering system. Operators of these existing wells then must choose between shutting in or throttling the well, employing other technologies to use the gas, reinjecting the gas, or flaring. This is the situation in the Permian basin in New Mexico, where almost all of the producing wells are connected to gas-gathering infrastructure, but substantial flaring still occurs due to inadequate capacity or pressure restrictions in the pipelines and/or processing plants. Much of the flaring in the Bakken basin is also driven by capacity constraints. In reviewing applications to vent or flare in North Dakota, the BLM found that out of 1,292 applications to vent or flare received between September 2012 and August 2014, 887, or about 70 percent, were from wells that were already connected to a gas pipeline, but had pipeline capacity or pressure restrictions.
Flaring also occurs in the second situation identified above, when gas capture infrastructure has not yet been built out to a particular field or well, even though the well is expected to produce substantial quantities of gas. In many instances, operators or midstream processing companies plan to construct gathering lines, but the rate of oil well development outpaces the rate of development of capture infrastructure.
In both situations, lack of adequate planning and communication can result in flaring. North Dakota's recognition of this cause of flaring led the State to require an operator to provide an affidavit at the well permitting stage stating that the operator met with gathering companies and informed them of the operator's expected well development timing and production levels.
The BLM recognizes that in the aggregate, operators do not want to waste gas. It is a valuable commodity that operators can sell for a profit. But when the economic return on oil production is substantially higher than the economic return on gas production, as it has been in recent years, there is an economic incentive for individual operators to focus on oil development at the expense of gas-capture infrastructure. Thus, operators may not adequately plan and coordinate with midstream companies, schedule oil well development with gas capture capacity in mind, build infrastructure, or otherwise ensure adequate capacity. As the GAO noted, even though it would be profitable in many instances for a company to make investments to reduce venting and flaring, the operator may choose to invest instead in a new well that would be even more profitable.
A focus on oil development rather than gas capture may be a rational decision for an individual operator, but it does not account for the broader impacts of venting and flaring, including the costs to the public of losing gas that would otherwise be available for productive use, the loss of royalties that would otherwise be paid to States, tribes, and the Federal Government on the lost gas, and the air pollution and other impacts of gas wasted through venting or flaring. A single operator's focus on its own operations can also produce a skewed assessment of the returns on investment in capture infrastructure across an entire area, where shared infrastructure may lower costs relative to the returns from the sale of gas.
Thus, a decision to vent or flare that may make sense to the individual operator may constitute an avoidable loss of gas and unreasonable waste when considered from a broader perspective and across an entire field. Further, as capture technologies improve, the economics of capture are improving for individual operators.
The BLM's proposed approach would reduce venting and flaring through a combination of measures: Prohibiting venting except in a narrow range of circumstances; reducing flaring by limiting the per-lease per-month rate of flaring; requiring operators to submit gas capture plans with their Applications for Permits to Drill new wells; requiring royalties on flared gas where appropriate; and simplifying both compliance with and administration of the venting and flaring requirements. The proposed rule would streamline the current regulatory regime by establishing thresholds and presumptions that initially apply across the board, but would maintain the BLM's ability to address individual situations through case-by-case determinations and exemptions where warranted.
With respect to venting, the proposal specifies that an operator must flare rather than vent gas, except in four specified circumstances: (1) When flaring the gas is technically infeasible (for example, because there is insufficient volume of gas); (2) When
The BLM is aware that venting may occur at gas gathering lines due to maintenance activities. We request comment on whether the proposed venting prohibition will sufficiently address these maintenance emissions.
The proposed requirements to reduce flaring focus on the routine flaring of associated gas from development oil wells. Associated gas represents the bulk of the current flared gas, and is easier to capture than other flared gas. To address this waste of gas, the BLM proposes to establish a limit on the average rate at which gas may be flared of 1,800 Mcf per month per producing well on a lease.
The BLM is proposing to retain the current exemptions from royalties and gas capture requirements for gas flared in other specified situations, as long as the operator has complied with the proposed requirements to minimize these losses. These exemptions include gas lost in the normal course of well drilling and well completion; well tests; emergencies, as defined in the regulations; and gas flared from exploration or wildcat wells, or from delineation wells (wells drilled to define the boundaries of a mineral deposit). As described in more detail below, these exemptions represent situations in which: (1) A well is least likely to be connected to a pipeline, and on-site capture technologies are least likely to be economical; or (2) Flaring is likely to be unavoidable or necessary for safety.
As noted, the primary means by which the BLM proposes to reduce flaring is by limiting the average rate at which gas may be flared to 1,800 Mcf/month, per producing well on a lease.
In essence, the BLM is proposing that, subject to limited exceptions, very high rates of flaring from a lease—that is, rates above the proposed 1,800 Mcf/month threshold—constitute unreasonable waste under the MLA. As discussed above, operators have multiple avenues to reduce high levels of flaring. One is to speed up connection to pipelines, and another is to boost compression to access existing pipelines with capacity issues. BLM believes there are also other options available to avoid this waste. The economics of alternative on-site capture technologies improve as quantities of gas increase. Imposing a limit on the overall rate of flaring on a lease would provide operators an incentive to implement these technologies, where net costs are not prohibitive, to allow the wells to produce oil at the maximum rate. Alternatively, an operator could slow production sufficiently to stay below a flaring limit. Slowing the rate of flaring is likely to conserve gas overall because less gas is lost before capture infrastructure comes on line (or is upgraded, in the case of a field with insufficient capacity).
To select an appropriate numeric limit for flaring, the BLM analyzed data indicating the average flaring rates across wells. The BLM used venting and flaring data reported to ONRR by operators of oil and gas leases on Federal and Indian lands. For the analysis, the BLM used the most recent full fiscal year of available data—records covering the time period from October 1, 2013, through September 30, 2014. The BLM extracted from the ONRR data 15,530 records that document more than 76 Bcf of natural gas flared from oil wells during the time period. These records represent monthly flared volumes on a lease or unit basis from over 2,000 unique leases or units that flared natural gas from Federal or Indian mineral estates. As the number of wells on a lease or unit that might contribute to the monthly flaring volume can affect the cost to capture, the BLM further reviewed the BLM Automated Fluid Minerals Support System database for the number of total active wells associated with the lease or unit. With the number of active wells linked to the lease or unit, the records were sorted in order of increasing average flare volume per month per well.
These data indicate that in 2014:
• A 1,200 Mcf/month/well threshold would have impacted about 20 percent of the oil wells flaring associated gas, which accounted for 91 percent of the gas flared;
• A 1,800 Mcf/month/well threshold would have impacted about 16 percent of the oil wells flaring associated gas, which accounted for 87 percent of the gas flared;
• An 2,400 Mcf/month/well threshold would have impacted about 13 percent of the oil wells flaring associated gas, which accounted for 84 percent of the gas flared;
• A 3,000 Mcf/month/well threshold would have impacted about 11 percent of the oil wells flaring associated gas, which accounted for 81 percent of the gas flared.
While these are average flaring volumes spread across all active wells, they represent an approximation of how oil well flaring is distributed across the spectrum of activity.
The BLM has analyzed the impacts of alternative flaring limits by adopting two simplifying assumptions. First, the BLM assumed that all over-the-limit quantities of gas would be captured instead of flared (an assumption that tends to overstate reductions in flaring); second, the BLM assumed that operators would comply only down to the level of the flaring limit and not below (an assumption that tends to
• A 1,200 Mcf/month/producing well threshold could conserve 80 percent of the gas flared;
• An 1,800 Mcf/month/producing well threshold could conserve 74 percent of the gas flared;
• A 2,400 Mcf/month/producing well threshold could conserve 69 percent of the gas flared; and
• A 3,000 Mcf/month/producing well threshold could conserve 65 percent of the gas flared.
These estimates were generated for the purpose of comparing alternative options for the flaring limit; the estimated overall impacts of the proposed flaring limit, combined with the effects on flaring of other elements of the rule, are presented in Section VI.B.4. of this preamble and Section 8.4.1. of the RIA. The BLM proposes in § 3179.6(b) to set a flaring limit of 1,800 Mcf per month per well, averaged over all producing wells on a lease. We believe this limit would effectively maximize flaring reductions while minimizing the number of affected leases. This proposed limit is consistent with Wyoming's and Utah's approaches: Wyoming and Utah limit flaring from a well to 60 Mcf/day and 1,800 Mcf/month, respectively, unless the operator obtains State approval of a higher limit.
The BLM recognizes that in the first few years of the rule, it may be difficult for operators to meet the newly proposed flaring limit across all of their existing operations, because operators of oil wells drilled prior to the effective date of this rule may not have planned for gas capture. To assist these operators in transitioning to the proposed flaring limits, we propose to phase in those limits over the first few years after the effective date of the rule. Specifically, we propose flaring limits of: 7,200 Mcf per month per well on average across a lease in the first 12 months in which the regulations are in effect; 3,600 Mcf per month per well on average across a lease in the second 12 months in which the regulations are in effect; and 1,800 Mcf per month per well on average across a lease thereafter. This approach of phasing in the flaring limits is intended to allow operators initially to focus their resources on addressing wells with the highest rates of flaring.
Lessees that entered into Federal and Indian leases prior to the imposition of the proposed flaring limits (depending on the location of their wells) may have limited options for substantially minimizing waste. As a result, the BLM believes it is appropriate and necessary to provide an exemption to ensure that no lessee is entirely deprived of its ability to develop an existing Federal or Indian lease.
Thus, the BLM proposes in § 3179.7 to provide existing lease holders with the possibility of obtaining an exemption to the applicable flaring limit. Specifically, we propose to provide that an existing lease holder may apply for an alternative flaring limit or, under specific circumstances, may qualify for a renewable, 2-year exemption from the flaring limit. These provisions are intended to help existing operators transition to the proposed regulatory regime; operators on new leases would have more flexibility to plan for gas capture ahead of drilling, and thus would not be eligible for either form of exemption.
The alternative flaring limit provision would apply to any operator (operating on an existing lease) that demonstrates, to the BLM's satisfaction, that the flaring limit specified in the regulations would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
In making the determination of whether a lease qualifies for an alternative flaring limit, the BLM would consider the costs of capture and the costs and revenues of all oil and gas production on the lease. For any operator that made a sufficient showing, the BLM would set an alternative flaring limit. The BLM would aim to set this alternative limit at the lowest level that would not cause the operator to cease production and abandon significant recoverable oil reserves.
The proposed standard for approving an alternative flaring limit is similar to the existing standard in NTL-4A for approving venting or flaring of oil well gas. NTL-4A allows the BLM to approve flaring if it is justified by data showing that “the expenditures necessary to market or beneficially use such gas are not economically justified and that conservation of the gas, if required, would lead to the premature abandonment of recoverable oil reserves and ultimately to a greater loss of equivalent energy than would be recovered if the venting or flaring were permitted to continue.”
To make the proposed showing, an operator would have to provide information about the quantity of flaring from the lease, projected costs of capture (including an evaluation of on-site approaches), and projected prices and returns on oil and gas production from the lease. Where operators need to project future costs and returns, the projections would be required to cover either the life of each lease or the next
The BLM believes that requiring the information specified in this proposal to support a request for an alternative flaring limit would not impose substantial new paperwork burdens on operators, given the information currently required to be submitted under NTL-4A. In addition, given the rigor of the qualifying requirements, we do not expect many lease holders to apply for an alternative flaring limit, further limiting the potential burden. We request comment, however, on this point.
Unlike the alternative flaring limit, the renewable exemption would provide certain operators with a complete exemption from the flaring limit, for a period of 2 years. The BLM generally prefers to assess the need for alternative flaring limits on a case-by-case basis, but we recognize that it may be more efficient to grant a short-lived, across-the-board exemption to a small class of operators that are: (1) Operating at significant distances from gas processing facilities, and (2) Generating high volumes of associated gas, such that capture and sale of the gas is plainly infeasible with current technologies.Thus, the proposed rule identifies three criteria that an operator must meet to qualify for an exemption from the flaring limit. Specifically, the BLM proposes that operations on an existing lease would qualify for an exemption from the flaring limit if: (1) The lease is not connected to a gas pipeline; (2) The closest point on the lease is located more than 50 straight-line miles from the nearest gas processing plant; and (3) The rate of flaring or venting from the lease exceeds the applicable flaring limit by at least 50 percent.
There are two reasons why the BLM believes that meeting all three of these criteria would be sufficient to demonstrate that an operator on an existing lease would be unlikely to be able to meet the flaring limit with today's technologies. First, a 2015 study by the entity Carbon Limits AS, titled
Second, while operators could respond to the flaring limit by deferring production, that is unlikely to be an option for operators on existing leases that are flaring more than 50 percent above the applicable limit. For these operators, reducing flaring below the limit would require reducing production by one-third or more. Thus, the BLM believes that leases meeting these distance and flaring rate criteria should qualify for an automatic exemption from the flaring limit.
To obtain the exemption, the BLM proposes to require that an operator submit a Sundry Notice with an affidavit certifying that the lease meets the specified criteria. The authorizing officer would then have the opportunity to verify the accuracy of the submission.
Because the circumstances supporting an exemption may change over time, the BLM proposes that the exemption would extend for 2 years, and could be renewed by the operator with submission and BLM approval of a new Sundry Notice.
To assist the BLM in finalizing the proposed flaring limit, we request comment on:
• The proposed 1,800 Mcf/month/well limit on the quantity of flared gas;
• Whether the flaring limit should be 1,200 Mcf/month/well, which would likely further reduce flaring, or 2,400 Mcf/month/well, which would likely reduce compliance costs for operators, but increase flaring above the amount anticipated by the proposed rule;
• Operators' likely response(s) to the proposed 1,800 Mcf/month/well limit (that is, the degree to which operators would respond by deploying on-site capture technologies, increasing capture capacity, speeding connections to pipelines, or slowing production, or with some combination of those responses);
• The proposal to phase-in the flaring limits and the specific limits proposed for year-one and year-two;
• The proposed provisions for operators to obtain an alternative flaring limit; and
• The proposed criteria for operators to qualify for the renewable, 2-year exemption, as well as the proposed 2-year duration of the exemption and the opportunity for renewal.
The BLM is also proposing that prior to drilling a new development oil well, an operator would have to evaluate the opportunities and prepare a plan to minimize waste of associated gas from that well, and the operator would need to submit this plan along with the APD.
The BLM proposes to amend § 3162.3-1 to require an operator to submit along with its APD a plan to minimize waste of gas from the well to the degree reasonably possible. Failure to submit a complete and adequate waste minimization plan would be grounds for denying or disapproving an APD.
The plan must set forth a strategy for how the operator will comply with the proposed requirements to control waste from venting, flaring, and leaks, and it must explain how the operator plans to capture associated gas upon the start of oil production, or as soon thereafter as reasonably possible. The waste minimization plan must include specified information, including: Anticipated well completion timing; anticipated gas production rates, durations, and declines; a map and information on the locations and operators of nearby gas pipelines and processing plants; proposed routes and tie-in points; pipeline capacities, throughputs, and expansion plans, if known; an evaluation of opportunities for alternative on-site capture approaches, if pipeline transport is
While the BLM is proposing to require submission of a waste minimization plan together with the APD, we are not proposing to include the submitted plan as an element of the APD or otherwise to enforce the terms of the plan.
The BLM believes that requiring submission of a waste minimization plan would ensure that as an operator plans a new well, the operator has the information necessary to evaluate and plan for gas capture. This requirement would also ensure that the operator provides this information to the companies most likely to install and operate the necessary gas capture infrastructure—namely, midstream processing companies operating in the area. Both procedural steps are vitally important to development of a robust gas capture system for a new well.
As with development of an environmental analysis under the National Environmental Policy Act, the BLM believe that significant progress can be made by requiring that operators take these procedural steps prior to drilling. Further, the BLM believes that making the elements of the plan enforceable (for example, by incorporating it in the APD) might create an unintended incentive for operators to understate the degree of capture they anticipate achieving, or to write a very general plan, with few specifics. As a result, the BLM believes more can be achieved by requiring operators to develop a thorough and practical plan prior to submitting their Applications for Permits to Drill. The plan requirement is intended to assist operators in better preparing to comply with the proposed flaring limits.
The information required by this proposed provision is comparable to the information North Dakota requires to be included in the gas capture plan that each operator must provide. North Dakota requires that the gas capture plan include: A detailed gas gathering pipeline system location map identifying the location of connections to the gathering system and processing plants, as well as the names of gas gatherers and locations of lines for each gas gatherer in the vicinity; information on the existing line to which the operator proposes to connect, including the maximum current capacity, current throughput, and gas gatherer issues or expansion plans for the area (if known); a flowback strategy including the anticipated date of first production, and anticipated oil and gas rates and duration; the amount of gas the applicant is currently flaring; and alternatives to flaring, including specific alternate systems available for consideration and the expected flaring reductions if such plans are implemented.
Under proposed § 3179.8, the BLM would require operators to report the quantities of all flared and vented gas. In determining the quantity of gas flared or vented, operators either estimate the volumes using engineering protocols or measure the volumes with gas meters. Meters generally produce more accurate results, but are also more costly. Thus, the BLM proposes to specify when operators may estimate the volumes of flared or vented gas, and when operators must measure the quantities for reporting purposes. Specifically, the BLM proposes that when the combined total of an operator's flaring and venting reaches least 50 Mcf of gas per day from a flare stack or manifold, the operator must measure rather than estimate the volume lost (
The BLM believes that in calculating small volumes of lost gas, any additional accuracy provided by meters may not justify their additional cost. Accordingly, the proposed rule would allow operators to estimate rather than measure volumes of lost gas below 50 Mcf. The BLM proposes to require measurement when gas losses are at least 50 Mcf per day because as the volume of gas flared nears 60 Mcf/day it is effectively nearing the 1,800 Mcf/month limit, and at that point accurate measurement of that volume becomes increasingly important for compliance and enforcement purposes. Moreover, as the volumes of gas flared increase, the economics of gas capture become more favorable, and the importance of using more refined data increases. We request comment on this proposed approach.
The requirement to meter flares is estimated to pose compliance costs of $7,500 per meter and operating costs of about $500 per meter per year. Assuming an equipment life of 10 years, the cost per meter is about $1,570 per year when costs are annualized using a 7 percent interest rate, or $1,380 per year using a 3 percent interest rate. In total, we estimate that the proposed flare metering requirement would impact 635 operations in 2017, with that number increasing on an annual basis to an estimated 1,175 operations in 2026. We estimate compliance costs ranging from $1.0-1.8 million per year when the capital costs of equipment are annualized with a 7 percent discount rate or $0.9-1.6 million per year when the capital costs of equipment are annualized with a 3 percent discount rate. Since these sources are not addressed by the EPA's proposed 40 CFR part 60 subpart OOOOa, the estimated impacts of the requirements are not influenced by that proposal.
The requirement to limit gas flaring to 1,800 Mcf/month per average well on a lease may result in a range of potential benefits and costs depending on operator response, commodity prices, and the levels of flaring in future years. Operators could choose to comply by immediately using the excess gas on-site or deploying on-site capture technologies; they could briefly slow oil production while they expand capture capacity, where such expansion is cost-effective; or they could defer some portion of their production. We request comment on the likely balance among these response approaches, and the likely volume and duration of any partial deferment in oil production.
We considered this range of responses in estimating the costs and benefits of the flaring provisions, although we recognize that these estimates are subject to significant uncertainty, given the uncertainty about operator response. In designing the analysis, we looked at data for leases in North Dakota and New Mexico with respect to characteristics that might influence an operator's choice of how to comply with the flaring limits. Specifically, we identified whether wells on the lease were
We estimate that the proposed flaring limits, including the 3-year phase-in period, would affect an estimated 435-885 leases in any given year. These requirements could pose total costs of about $32-68 million per year (7 percent discount rate) or $26-43 million per year (3 percent discount rate). Because these requirements would drive additional capture of gas, the flaring limits are also projected to pose total cost savings (from the value of the captured gas) of about $40-58 million per year (7 percent discount rate) or $40-64 million per year (3 percent discount rate). We also estimate that they would increase natural gas production by 2.5-5.0 Bcf per year, and increase NGL production by 36-51 million gallons per year. The net benefits of these requirements are estimated to range from negative $10 to positive $8 million per year (7 percent discount rate) or $13-30 million per year (3 percent discount rate). Also, we expect there would be additional environmental benefits associated with the productive use of the gas downstream.
Along with the other aspects of NTL-4A, it is necessary to update the NTL-4A provisions regarding the applicability of royalties. As noted above, this proposal would clarify the determination of whether routine flaring from a production well is considered an avoidable waste of gas subject to royalties. Requiring royalty payments on wasted quantities of gas does not compensate for all the harm to the public from that waste, but it at least ensures that the public does not lose the royalty revenue they would have received had the gas been put to productive use.
The BLM is proposing in § 3179.4 to maintain the general approach of NTL-4A for distinguishing between avoidable and unavoidable losses of gas. The proposed rule would reduce regulatory burden and confusion, however, by providing additional and more specific requirements, and it would modify the NTL-4A approach with respect to flaring from wells that are already connected to gas capture infrastructure.
The BLM proposes to determine that a loss of gas is unavoidable if all of the following four conditions are met. (1) The operator has not been negligent; (2) The operator has complied with all applicable requirements; (3) The operator has taken prudent and reasonable steps to avoid waste; and (4) The gas is lost from any of the following specified operations or sources, subject to the applicable limits or conditions specified in the proposed regulations: Emergencies; well drilling; well completion and related operations; initial production tests and subsequent well tests; exploratory coalbed methane well dewatering; leaks; venting from conforming pneumatic devices in the normal course of operation; evaporation from storage vessels; and downhole well maintenance and liquids unloading. Where these losses result from flaring, the BLM is proposing to establish quantity and/or timing limits on gas that may be flared royalty-free, such as the definition of what is considered an emergency and the limits on royalty-free flaring for well testing. Beyond these limits, continued losses would generally be considered avoidable and subject to royalties, except that, with respect to testing, the BLM may approve an operator's request for royalty-free flaring beyond the specified limits.
In addition, the BLM is proposing to find a loss of gas unavoidable where produced gas is flared from a well not connected to gas capture infrastructure, as long as the BLM has not otherwise determined that the loss of gas is avoidable, subject to the 1,800 Mcf/month limit in § 3179.6. In some cases, the effectiveness and affordability of on-site capture technology may mean that an operator could avoid flaring gas from a well not connected to capture infrastructure. At this time, however, on-site capture technology is not always effective and affordable; thus, the BLM is not proposing to find all flaring of associated gas from development wells to be avoidable.
The specifics of the proposal with respect to unavoidable losses depend on the category of loss. With respect to emergencies, NTL-4A currently authorizes royalty-free flaring of gas without approval from the BLM, but the proposed rule would clarify and narrow the scope of this exemption. As proposed under § 3179.105, emergencies result in infrequent and unavoidable flaring (or venting), and they may include failures of equipment located on the lease, relief of abnormal system pressures, or other unanticipated conditions. Operators may flare under this exemption for up to 24 hours per incident, and for no more than three emergencies per lease within a 30-day period. The BLM proposes to clarify that emergencies do not include: More than three failures of the same equipment within 365 days; failure to install adequate equipment to capture the gas; failure to limit production when the production rate exceeds the capacity of the related equipment; scheduled maintenance (whether by the operator or downstream facilities); or operator negligence. The BLM believes that repeated failure of the same piece of equipment within a given span of time indicates that the equipment is not properly sized or may need to be replaced, and that the operator should have taken action to address the problem. The BLM requests comment on the specific failure frequencies over a given time-period that would tend to indicate avoidable incidents.
With respect to flaring during well drilling and completion, the BLM proposes under § 3179.101 that gas produced during normal well drilling operations and then flared would be deemed unavoidably lost. Similarly, under proposed § 3179.102, gas produced during well completion and post-completion drilling fluid recovery or fracturing fluid recovery operations would be deemed unavoidably lost when flared, subject to a volume limit. Under proposed § 3179.103, gas from initial production testing may be flared and deemed unavoidably lost until the first of the following occurs: (1) The operator has adequate reservoir information for the well; (2) 30 days (90 for coal-bed methane dewatering) have passed; (3) The operator has flared 20 MMcf of gas, including any gas flared that was produced during well completion and post-completion fluid recovery; or (4) Production begins.
The 20 MMcf limit is lower than the maximum volume of royalty-free flaring authorized under NTL-4A (50 MMcf). The BLM's experience in the field
Under proposed § 3179.104, during well tests subsequent to the initial production test, the operator may only flare gas for 24 hours royalty free, unless the BLM approves otherwise.
Operators would no longer need to apply for approval of flaring under the preceding conditions. Any gas flared in excess of these limits, however, would be deemed avoidably lost and subject to royalties, except where the BLM approved a request to extend the limits. In addition, regardless of whether the gas is subject to royalties, BLM also proposes under § 3179.8 that the operator must measure or estimate all quantities of gas flared and vented, including those that are deemed unavoidably lost, and report these quantities to ONRR.
Under proposed § 3179.4(b), all losses of gas not specifically found to be unavoidable would be considered avoidable. Proposed § 3179.5(a) would subject all avoidably lost gas to royalties. One key consequence of this proposal is that royalties would apply to associated gas flared from a development well that is already connected to capture infrastructure.
The BLM believes that where operators are connected to capture infrastructure, but are nevertheless flaring, they have made an economic choice to flare, and flaring in those instances should not be considered an unavoidable consequence of oil production. Most flaring at wells already connected to pipelines occurs when wells are bumped off the pipeline due to pressure or capacity constraints, or when downstream equipment is brought down for maintenance. Where wells are already connected to gas capture infrastructure, midstream companies and operators have presumably already found that gas capture pays for itself. Nonetheless, operators may choose to expand production beyond the capacity of existing capture infrastructure, or to do so faster than capture infrastructure can be expanded (where capacity issues can be addressed with installation of additional compression, the rate of expansion is often in the operator's control). This may be a rational business decision for an operator, but with better planning or more deliberate development, both the oil and gas resources could be developed without waste.
Further, operators may be able to use alternative on-site gas capture equipment to put the gas to productive use during any period in which gas production exceeds transport capacity. Similarly, when downstream equipment is temporarily brought down for maintenance, operators could curtail production for a short period or use on-site capture equipment to avoid wasting gas in the interim.
The BLM considered, but did not include in the proposed rule text, a range of supplemental or alternative approaches to the flaring limit and royalty provisions described above. For example, one alternative approach that BLM considered for increasing capture of associated gas was to rely solely on royalties on flared gas to discourage flaring. Under this approach, all flaring of associated gas would be presumptively subject to royalties. Similar to the current standard under NTL-4A, operators could then obtain an exemption to the requirement to pay royalties by showing that a requirement to conserve the gas would cause the operator to cease production and abandon significant recoverable oil reserves. To support such a claim, the operator could be required to provide: The projected costs of each technically viable method of capturing and/or using the gas (including, if applicable, pipelines, removal of NGLs, CNG, LNG, and electricity generation); the current return on investment for the oil and gas operation on the lease; the projected return on investment for the oil and gas operation if some or all of the gas were captured; projected oil and gas prices and production volumes; the location and capacity of the closest pipelines; and other relevant information. In making the determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease.
While market-based mechanisms, such as royalty imposition, can be highly effective policy instruments, and we do propose to charge royalties on gas flared above the 1,800 Mcf/month limit because we believe flaring above that level is avoidable, we do not believe that royalties on flared gas alone would curtail flaring. At current gas prices, oil prices, and royalty rates, applying royalties to flared gas does not provide a sufficient incentive for operators to invest in gas capture to any appreciable degree. This is evident in areas such as Carlsbad, New Mexico, where most operators are currently paying royalties on associated gas that is flared, and in spite of those payments, rates of flaring have not changed appreciably since 2013. The BLM would not expect the imposition of royalties at the current royalty rate to lead to a significant increase in gas capture as long as the economic return on the oil production is substantially higher than the economic loss from the flared gas. The BLM requests comments on this conclusion.
A more significant royalty-based approach to flaring would be to apply a higher royalty rate to all production from a lease on which the operator is routinely flaring gas from development wells. This concept is discussed in more detail in Section V.C. of this preamble.
Another alternative to the proposed approach to flaring would be to distinguish between new and existing wells. The current proposal applies the same flaring requirements to both. The BLM is, however, considering including a complete prohibition on routine flaring of associated gas from new development wells. This approach would shift the burden of flaring from the public, which currently absorbs the costs of flaring, to operators, which have greater capacity to anticipate and plan for capture infrastructure to be ready at the time they shift from exploration to development in a given field. The BLM requests comment on this approach.
Finally, the BLM is requesting comment on other innovative approaches to reduce wasteful flaring and determine when flaring should be subject to royalties. In evaluating alternative approaches suggested in comments, we would consider a variety of factors, including the approach's effectiveness in: Increasing gas capture; reducing waste and compensating the public through royalties; enhancing regulatory clarity and transparency; reducing uncertainty for operators; minimizing inconsistency across BLM offices; minimizing cost, paperwork, and any other burdens on operators; minimizing administrative burden on the BLM; increasing overall practical workability; and satisfying existing legal authorities.
As discussed in detail in the RIA, using data from the EPA GHG Inventory, we estimate that about 4.35 Bcf of natural gas was lost in 2013 as a result
Multiple studies have found that once leaks are detected, the vast majority of them can be repaired at low enough cost that the captured gas provides a positive return to the operator. For example, the Carbon Limits study found that 97 percent of the total leak rate could be repaired with a positive return, even at low producer gas prices of $3 per Mcf.
The term “Leak Detection and Repair” (LDAR) refers to both the practices and programs that operators put in place to inspect for and repair leaks, and the specific technologies and methods the operators use to detect leaks during inspections. Recent technological developments have reduced the cost of leak detection while simultaneously improving operators' ability to detect less obvious leaks. Traditional methods coupled with new technology can also be effective.
States are beginning to take advantage of these new technologies. Colorado, for example, requires instrument-based emission monitoring as part of an LDAR program that applies to well production facilities and compressor stations.
The AVO method consists of physically inspecting the facilities—looking, listening, and smelling for leaks. AVO inspections have traditionally been the backbone of an inspection program, and BLM inspectors typically use this method when inspecting well and facility sites. The use of AVO inspections is most effective in detecting obvious and significant emissions-release events, resulting in the cost-effective reduction of high-volume leaks. The BLM believes AVO is affordable for the many small operators that only operate a few well sites each. Costs associated with the AVO method are largely for labor, paying for qualified technicians and their mileage to and from the well or facility sites.
Portable monitoring instruments or portable analyzers detect hydrocarbon leaks from individual pieces of equipment. These analyzers may use any of a variety of methods of detection, including catalytic ionization, flame ionization, photoionization, infrared absorption, and combustion, and they are generally used only to detect and measure the quantity of a single component of the vapor, such as methane. These analyzers are sensitive and can detect emissions at extremely low concentration levels. Typical portable analyzers range in cost from $3,000-$12,000.
One standard approach for using portable analyzers is “Method 21,” the EPA's method for detecting VOC emissions from leaking equipment.
A newer technology that operators and inspectors are increasingly using for leak detection is optical gas imaging (OGI). OGI uses infrared detectors (commonly called “infrared cameras”) to provide visual images of gas emissions in real time. The OGI instrument can be used to monitor a wide range of oilfield equipment and its effectiveness as a means for detecting leaks is widely recognized.
OGI costs more than AVO approaches, but it also detects more leaks, which can result in additional gas savings. The GAO noted that infrared cameras allow users to rapidly scan and detect vented gas or leaks across wide production areas. The GAO specifically recommended that the BLM consider the expanded use of infrared cameras, where economical, to improve reporting of emission sources and to identify opportunities to minimize lost gas.
Infrared cameras have high capital costs, and they also require calibration, maintenance, and training. As a result, while some operators purchase and operate this equipment themselves, others contract with specialized firms for leak detection surveys using this equipment. For example, the equipment may cost from $85,000 to $100,000 or more, with packages that include many peripherals costing upwards of $125,000. Batteries, chargers, and other required peripherals can add $5,000 to $10,000. Service provider rates may be in the range of $500 per day to $2,000 per week, while annual service contracts may range from $5,000 to $10,000.
Studies and some operators' experiences indicate that LDAR programs based on the use of infrared cameras actually save operators money overall, while substantially reducing waste. For example, the Carbon Limits study found that because leaks are not evenly distributed across all facilities, not every leak survey finds leaks and saves money for the particular operator. But when considered across a broader set of facilities (such as those located on BLM-administered leases or a set of facilities owned by a single operator), the study found that these programs have either cost-neutral or positive returns on average, depending on the type of facility surveyed.
Specifically, the Carbon Limits study found that for well sites and groups of wells, about one-third of the facilities had no detectable leaks, 7 percent had leaks above 500 Mcf per year, and the remainder had leaks of less than 500 Mcf per year. (To put this number into perspective, a typical home uses 74 Mcf of gas a year.
When aggregated across a larger group of facilities, rather than being evaluated on a facility-by-facility basis, the Carbon Limits study found that these infrared camera leak surveys produce net cost savings.
Another possibility for leak detection is continuous emissions monitoring. Continuous Emissions Monitoring Systems (CEMS) are commonly used as a means of monitoring various components of a large industrial source's emissions stream, including oxygen, carbon monoxide and carbon dioxide, for compliance with EPA or State air emissions standards. More recently, researchers have been evaluating the possibility of adapting the technology for use in identifying leaks in and around oil and gas operations.
There is also extensive ongoing work to develop other, more effective and less costly advanced leak detection technologies. For example, DOE initiated an effort to advance methane-sensing technologies through the Advanced Research Projects Agency—Energy (ARPA-E) MONITOR (Methane Observation Networks with Innovative Technology to Obtain Reductions) program.
An effective LDAR program depends not just on the technology used to detect leaks, but also on the overall approach an operator uses to inspect for leaks, conduct preventative maintenance, and repair leaks that are found. Two of the largest operators in one of BLM's field offices conduct routine operations checks, which typically use AVO inspection methods. In addition to well site inspections, a preventative maintenance program is often used. Adherence to a properly designed preventive maintenance program proactively minimizes equipment failures and gas losses from leaks. In general, a maintenance program may consist of a variety of activities that are applicable to operating location, type of operations, and equipment used. An operator will design the preventive maintenance program that is most suitable for the site. These efforts include periodic inspection (AVO inspection and general equipment inspection on at least a monthly basis) and service of components that are not leaking, material selection appropriate to service (
For example, one major operator in northwest New Mexico, which oversees 10,000 wells in the San Juan Basin, has its lease operators visit each well site each week.
The BLM believes that LDAR programs are a cost-effective means of reducing waste of gas in the oil and gas production process, based on the State programs, studies, and findings discussed above. Thus, the BLM is
The BLM's proposed approach, outlined below, is similar to the requirements adopted by Colorado and Wyoming. EPA's proposed regulations to reduce methane emissions from the oil and gas production sector also include fugitive emission requirements, which would apply to certain new and modified oil and gas production facilities. Specifically, the EPA's September 18, 2015 proposal, if finalized, would require that new, reconstructed, and modified well sites and compressor stations conduct regular (semi-annual, annual, or quarterly) fugitive emissions surveys using optical gas imaging technologies.
The BLM proposes under § 3179.302 to require that operators use an instrument-based approach to leak detection. Advances in OGI leak detection technology, in particular, now allow for affordable detection of more, smaller, and less accessible leaks, compared to what would be identified through a pure AVO approach. Both Colorado and Wyoming require operators to use an instrument-based approach.
The BLM believes that optical gas imaging is currently the most effective instrument for leak detection, but infrared cameras may be more expensive than portable analyzers, which are also reasonably effective in certain situations. As infrared cameras are used more commonly, and the capacity to conduct infrared-based surveys increases, the BLM believes that the economics of this method will become increasingly favorable for identifying leaks at a wide variety of operations. At present, however, infrared cameras are most cost-effective when used to inspect large numbers of facilities. Thus, the BLM believes it is appropriate to require an infrared camera-based program for operators with larger numbers of wells, and to allow operators with fewer wells to use portable analyzers instead.
The BLM also seeks to account for advances in continuous emissions monitoring technology, and also for other advances in leak detection technologies, which may result from ongoing technology development efforts such as the DOE ARPA-E MONITOR program. We believe it is important to ensure that operators be allowed to take advantage of any new, more effective, and less expensive technologies, as they become available. Accordingly, the BLM is proposing to require, under § 3179.302(b), that operators that have 500 or more wells within a BLM field office jurisdiction must use one of the following three approaches to LDAR: (1) An optical gas imaging device like an infrared camera; (2) A new, equally advanced and effective monitoring device, not yet developed and therefore not listed in the rule text, which the BLM would review and approve for use by any operator;
Operators with fewer than 500 wells located within a single BLM field office's jurisdiction could use any of these three LDAR approaches, but they would also have the option of using a portable analyzer device, such as a catalytic oxidation, flame ionization, infrared absorption or photoionization device, operated according to manufacturer specifications, and assisted by AVO inspection.
The BLM requests comment on the above LDAR proposal. In particular, comments should address the appropriateness of requiring the use of optical gas imaging devices in some or all circumstances. We request data and comment on the appropriateness of using the 500-well threshold to identify those larger operators for whom the economics of these devices may be more favorable, whether optical gas imaging is cost-effective for operators with a smaller number of wells, and should therefore be required for all operators.
Further, the BLM requests comment on whether the above suite of options for LDAR (three options for large operators, four for smaller operators) is reasonable to allow operators flexibility to design and implement leak detection programs that work for them, while still setting sufficiently rigorous minimum standards to ensure that all such programs are comprehensive and effective. In particular, we request comment on whether the standard for BLM approval of an alternative approach (that it meets or exceeds the effectiveness of an optical gas imaging device used at the frequency specified in proposed § 3179.303(a)) provides sufficient guidance to the BLM, and whether the standard would result in adequate consistency across field offices.
The BLM is also proposing under § 3179.302(a)(4) that operators who choose to use portable analyzers would be required to use them according to manufacturers' specifications. The EPA's Method 21, discussed above, is one specific method for ensuring that portable analyzers that are capable of detecting fugitive emissions (or leaks) are used in a manner that produces accurate results. The BLM is not proposing to require the use of Method 21. The BLM requests comments on: (1) Whether this rule should require the use of Method 21 if an operator chooses to use a portable analyzer; (2) The adequacy of manufacturers' use specifications to produce accurate results regarding the presence or absence of a leak; and (3) Whether there are other use protocols for portable analyzers that produce accurate results for leak detection purposes.
The BLM also requests comment on whether the regulations should include a threshold volume of gas that will be deemed a leak with respect to gas losses detected by portable analyzers, and if so, what that threshold volume should be. In contrast to optical gas imaging, portable analyzers are so sensitive that, at the lowest measured levels, it may be difficult to tell whether the analyzer is detecting a leak or simply registering background levels of the measured gas. The BLM requests comment on whether it should provide that a release of gas
Another key element of an effective LDAR program is to define the frequency of inspections. Colorado bases its frequency-of-inspection requirement on the level of estimated uncontrolled emissions from storage vessels or the potential to emit VOCs from all facility components.
Multiple studies have found that a relatively small percentage of facilities are responsible for the majority of leaks and for most of the wasted gas (this is known as a “fat-tail” problem).
Increasing survey frequency allows more leaks to be found, but also increases costs. Accordingly, the BLM aims to establish an approach to survey frequency that reduces the most waste at the lowest cost. The Carbon Limits study analyzed the impact of survey frequency by analyzing over 400 annual surveys.
Thus, the BLM is proposing under § 3179.303 to require all operators to conduct semi-annual surveys of their sites—defined in proposed § 3179.303 to mean a discrete area suitable for inspection in a single visit and containing wellhead equipment, compressors, and facilities
The BLM has proposed three or more leaks at a site as the threshold for increasing the frequency of inspections, and two or fewer as the threshold for decreasing the frequency of inspections, as a possible way to distinguish between sites with very little loss from leaks and sites with more significant leak problems. The BLM requests comment on whether these are the appropriate numbers of leaks to use as thresholds, and if not, what the threshold levels should be.
Once a leak is identified, the BLM proposes under § 3179.304 that the operator would be required to repair the leak as soon as practicable, but no later than 15 calendar days after discovery, unless there is a good cause necessitating a longer period. The BLM believes that a “good cause” for a longer period would be something that prevents the operator from repairing the leak within the 15 calendar day period and that the operator could not reasonably have prevented. Examples of potential good cause for a longer period include the unavailability of a needed part or severe weather conditions that prevent safe access to the site. Preferred scheduling for maintenance would not be an example of good cause for delay in leak repair. If a delay in repair is attributable to good cause, the operator must notify the BLM of the cause and must complete repairs within 15 calendar days after the cause of delay ceases to exist. The BLM proposes to require operators to verify the effectiveness of a repair within 15 calendar days after completion using the same leak detection method used to find the leak.
The BLM proposes under § 3179.305 that operators be required to keep and make available to inspectors records documenting the dates of leak inspections, the sites where any leaks are found, and a description of each leak. Operators would also need to record when leaks were repaired, and the dates and results of follow-up inspections to verify the effectiveness of the repairs.
The BLM is aware that some well sites and compressor stations could be subject to both the fugitive emission requirements of the proposed EPA rule and the requirements of the proposed BLM rule. In addition to our request for comments discussed above, regarding further alignment of the BLM rule and the EPA rule, we are proposing that an operator may demonstrate to the BLM that it is complying with the EPA LDAR requirements in lieu of the BLM LDAR requirements, for some or all of the operator's sites. We specifically request comment on this element of the proposal, including whether it would help to reduce the compliance burden on operators, whether it could compromise program effectiveness in any way, and whether it may present challenges for BLM and EPA to administer and enforce. The BLM expects that the LDAR requirements ultimately adopted by the EPA for new and modified well sites would be as effective in minimizing the volume of gas lost through leaks as the final BLM requirements, and we should be able to confirm this expectation prior to finalizing this proposed provision.
In addition to the BLM's proposed approach, we are taking comments on other possible approaches to reducing waste through LDAR requirements.
One small variation on the proposed LDAR approach would be to require that LDAR inspections be conducted by third parties. Requiring third parties to conduct inspections could provide additional assurance that surveys are conducted effectively and produce accurate results. While some operators conduct their own inspections, many already contract with third parties that provide the equipment, trained operators, and detailed reports. The BLM acknowledges, however, that third-party contracting might in some instances be more costly and might prove unnecessary for operators that have their own equipment and substantial in-house expertise. A variation on this option would require periodic third party inspections as a means of confirming the efficacy of an operator's internal leak detection program, while still allowing most inspections to be conducted in-house, if an operator so chooses. For example, the BLM could require that operators contract with a third-party to perform at least one annual or biannual inspection. The BLM requests comments on these options.
A second possible variation would be to constrain approval of alternative leak detection approaches. For example, the BLM could limit authorization of alternatives to new technologies and devices, rather than new detection programs. (That is, the final rule could eliminate proposed § 3179.302(a)(3).) Another approach would be to limit authorization for an alternative leak detection program under proposed § 3179.302(a)(3) to operators that already have an effective program in place as of the effective date of this rule. That approach would reward operators that proactively invest in leak detection, but would require operators that do not make that proactive investment to comply with the standards established in the regulation. The BLM requests comment on these variations.
A third possible variation would be to focus operators' LDAR efforts on higher production wells. For example, a stakeholder suggested that the BLM could require the development of an LDAR program at those wells in the top 75 percent of an operator's inventory, in terms of production volume, and address storage vessels separately. Under this suggested approach, the operator would be required to conduct an initial survey of its top-producing wells, and would then design an appropriate leak detection program, with a specified frequency based on the results of that survey.
Others have suggested modifying or waiving the LDAR requirements for stripper wells—a specific category of low-yield wells producing 15 bbl of oil-equivalent per day or less. In its 40 CFR part 60 subpart OOOOa rulemaking, for example, EPA proposed that new and modified wells producing 15 bbl of oil-equivalent per day or less be exempted from the LDAR requirements, or allowed to inspect less frequently, such as annually or on a one-time basis. Presumably, modifying the LDAR requirements for stripper wells relies on an assumption that the amount of leaked methane correlates with well production, and therefore frequent LDAR is not a cost-effective means of reducing methane emissions from low-producing wells. In addition, proponents of this approach assert that LDAR requirements for marginal wells would disproportionately impact small businesses.
This rulemaking does not propose a modified standard for stripper wells, because 85 percent of oil wells and 73 percent of gas wells on Federal and Indian leases meet the definition of stripper wells.
Thus, while reducing the frequency of leak detection inspections for stripper wells might decrease the costs of the leak detection requirement, we believe that approach would negate most of the expected benefits of the LDAR requirement for existing leases on Federal and Indian lands.
Moreover, the factual record available to the BLM indicates that requiring leak detection at stripper wells would produce significant gas savings. Recent studies do not support the suggestion that leak rate correlates with yield. Rather, these studies suggest that even low-yield wells can leak at significant rates.
Establishing a separate standard for stripper wells also would not align the proposed BLM requirements with the proposed EPA requirements. The EPA's standard for stripper wells applies only to new or modified wells that come online as stripper wells, not to wells that initially produce at higher rates, but eventually decline to stripper status. Based on our experience in the field, we believe that a very small number of wells would qualify for a relaxed standard under the EPA proposal. In our experience, most new wells produce at rates higher than 15 barrels-of-oil-equivalent per day, because operators are unlikely to invest in completing newly drilled wells that produce at very low rates.
Many of the stripper wells producing from Federal and Indian leases are existing wells that once produced at higher rates, but have declined to stripper status, and they therefore would not qualify for the EPA's LDAR standards for stripper wells. Thus, although the BLM recognizes the importance of harmonizing this rule with EPA's proposed 40 CFR part 60 subpart OOOOa rulemaking, establishing a different LDAR standard for existing stripper wells on Federal or Indian leases would not, in fact, advance that goal.
Another alternative approach to the proposed LDAR requirements would be to retain all of the elements of the proposed approach, except the basis for setting the required frequency of inspections. Specifically, rather than having the frequency vary based on the results of previous surveys, the inspection frequency would be set based on the type of facility being inspected. As noted previously, Colorado uses this method, with frequencies that range from monthly to one-time, depending on the type of facility and the level of uncontrolled VOC emissions.
One simplification of the Colorado approach would be to focus on sites with vibrating equipment or storage vessels. Industry stakeholders have stated that they find most leaks at sites with equipment that vibrates (
A different simplification of Colorado's system would be to distinguish between gas wells and oil wells, requiring more frequent inspections at gas wells and less frequent inspections at oil wells. EPA's emissions factors indicate generally higher volumes of fugitive emissions
The BLM requests comment on all of the LDAR variations discussed above. In particular, the BLM requests comment on:
• The initial frequency of surveys;
• Requiring more frequent surveys, such as quarterly;
• The concept of changing inspection frequency depending on the operators' record of past leaks;
• The triggers for increasing and decreasing inspection frequency (
• Whether the frequency of inspections should be the same across all of the sites on a lease, and if so, how to operationalize that requirement.
In connection with any comments related to modifying the inspection frequency for stripper wells, the BLM specifically requests submission of data regarding the relationship between well production and levels of leaked methane from a well site. The BLM also requests comment on whether it should require gas wells to be inspected quarterly and oil wells annually. While there is substantial uncertainty in the cost-benefit analysis of these provisions, with certain simplifying assumptions, the analysis indicates that this alternative approach could increase net benefits, compared to the proposed approach. As detailed in the RIA, the projected annual net benefits for a semi-annual inspection requirement for all wells range from $19-48 million, with the range largely depending on the year, compared to annual net benefits of $3-43 million (again largely depending on the year) with quarterly inspections for gas wells and annual inspections for oil wells.
In addition, the BLM requests comment on simply requiring semi-annual or quarterly inspections for all well sites, facilities, and compressor stations subject to the LDAR requirements, with no mechanism to increase or decrease inspection frequency based on how many leaks are found. A quarterly inspection requirement would track the Wyoming approach for the Upper Green River Basin. Requiring semi-annual or quarterly inspections for all sites would reduce the potential confusion of inspection frequencies that vary over time and across an operator's well sites. Tracking the required frequency for each discrete leak inspection site could be burdensome and prone to error and confusion. Requiring quarterly inspections would also maximize the gas savings from avoided leaks, although it would have higher costs than the other approaches discussed here. As with setting different frequencies for gas and oil wells, this approach would not track with the EPA's LDAR requirements, assuming that the EPA finalizes its proposed approach.
The BLM also requests comment on the approach of focusing the LDAR requirement on sites with vibrating equipment or storage tanks, perhaps by requiring a one-time inspection of all sites, but quarterly inspections of sites with such equipment. Would that approach successfully target sites that are most prone to significant leaks? Would it reduce costs for operators? And finally, could it readily be enforced?
Finally, the BLM notes that many of these LDAR approaches deviate from EPA's proposed approach. The BLM requests comment on the importance and implications of aligning BLM and EPA LDAR requirements.
Assuming that the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking, then the BLM expects that its proposed requirements would affect up to 36,700 existing wellsites, and pose total costs of about $69-70 million per year (using 7 percent and 3 percent discount rates). These requirements are also projected to result in cost savings of about $12-15 million per year (7 percent discount rate) or $15-17 million per year (3 percent discount rate), increase gas production by 3.9 Bcf per year, and reduce VOC emissions by 18,600 tpy. We estimate they would reduce methane emissions by 67,000 tpy, producing monetized benefits of $73 million per year in 2017-2019, $87 million per year in 2020-2024, and $100 million in 2025 and 2026. Thus, we estimate that these provisions would result in net benefits of $19-21 million per year in 2017-2019, $31-35 million per year in 2020-2024, and $43-48 million in 2025 and 2026.
If, for analytical purposes, we assume a baseline in which EPA does not finalize its proposed LDAR requirements, we estimate the following impacts from our proposed LDAR requirements. We project that the proposed requirements would affect up to about 37,000-38,000 wellsites per year, and pose total costs of about $70-71 million per year (using 7 percent and 3 percent discount rates). These requirements are also projected to result in cost savings of about $12-18 million per year (using 7 percent and 3 percent discount rates), increase gas production by 3.9-4.0 Bcf per year, and reduce VOC emissions by 19,000 tpy. We estimate they would reduce methane emissions by 68,000 tpy, producing monetized benefits of $75 million per year in 2017-2019, $88 million per year in 2020-2024, and $102 million in 2025 and 2026. Thus, we estimate that these provisions would result in net benefits of $19-21 million per year in 2017-2019, $30-35 million per year in 2020-2024, and $43-48 million in 2025 and 2026.
As noted, some operators reportedly already have leak detection programs in place. To the extent that these operators currently have LDAR programs that are approved by the BLM, the actual impacts of this proposal would be lower than these estimates.
Pneumatic controllers are automated instruments that control certain processes or conditions, such as liquid level, pressure, and temperature in oil and gas production, treatment, storage, and handling operations. Pneumatic controllers are operated by gas pressure, and the gas is emitted from the device when the device is active. Some types of controllers “bleed” gas continuously as part of their normal operations, while others emit gas intermittently. While these controllers can operate using any pressurized gas, for the purposes of this proposed rule, the term pneumatic controller means an instrument that is operated by natural gas pressure and emits natural gas.
Pneumatic pumps of different varieties are commonly used in oil and gas production and treating operations. For example, gas-assist glycol dehydrator pumps are used to circulate glycol in dehydrators. Chemical injection pumps are used to pump chemicals down a well to facilitate production or into a pipeline to prevent
As described in the RIA, using data from the EPA GHG Inventory, we estimate that about 5.4 Bcf of natural gas was lost in 2013 from pneumatic controllers on BLM-administered leases.
Pneumatic controllers and pneumatic pumps are common equipment at well site facilities. For well sites without electrical service, gas pressure is used as a ready energy source to operate this equipment. There are several options for minimizing the amount of natural gas that is used and emitted from existing controllers and pneumatic pumps, which bear a range of associated cost and practicality considerations.
As discussed earlier in § III.I.3, in the existing EPA NSPS rule (40 CFR part 60 subpart OOOO) for the oil and gas sector, the EPA established an emissions rate of 6 scf/hour as the upper limit for new and replacement pneumatic controllers (pneumatic controllers meeting this standard are referred to as “low-bleed” pneumatic controllers).
Existing high-bleed controllers can generally be replaced with models that use and emit less natural gas. For most applications, low-bleed controllers are available and make suitable replacements for high-bleed controllers. At facilities with a gas sales line, the replacement cost of low-bleed controllers is generally rapidly offset by gas savings. ICF identified replacement of high-bleed pneumatic controllers with low-bleed pneumatic controllers as one of the most cost-effective options for reducing methane. Specifically, ICF estimated that the replacement would save industry $2.65 per Mcf of avoided methane emissions.
The State of Colorado has prohibited use of “high bleed” pneumatic controllers, with limited exemptions.
In May of this year, the State of Wyoming adopted regulations that require operators in the Upper Green River Basin to replace high-bleed pneumatic controllers with low-bleed controllers by January 1, 2017.
Another option that is available in some situations is adding electrical service (power line, generator, or solar array) and replacing pneumatic controllers and/or pneumatic pumps with electric or compressed air controllers and pumps, which do not release any natural gas. Where electrical service is available, existing pneumatic controllers and pneumatic pumps could be operated by the addition of a compressed air system. Installing a compressed air system would involve adding a compressor and tubing to connect each controller and pump to the system. Alternatively, pneumatic controllers and pneumatic pumps could be replaced by electric models. At facilities with a gas sales line, the cost of replacing electric controllers and operating the power system would be at least partially offset by sale of the gas that would otherwise have been vented through operation of the pneumatic controllers and pneumatic pumps. Natural gas could be used to generate electricity to operate electronic controllers; based on the typical number of controllers at a well site and the energy requirements of controllers, however, the BLM does not believe this is the most efficient means of completing the operational objective.
One of the more common applications of this approach is to use solar powered electric controllers and pumps to replace individual pneumatic controllers and pneumatic pumps without replacing the power system for the whole facility. Solar pumps are often used to replace pneumatic chemical injection pumps, in particular. Chemical injection pumps are smaller pumps that inject chemicals into a pipeline to,
A third option for reducing gas losses from pneumatic controllers and pneumatic pumps is to add a low-pressure collection system that would capture the natural gas emitted from pneumatic controllers and pneumatic
The State of Wyoming has adopted regulations that require pneumatic pumps used in the Upper Green River Basin to destroy or capture emissions or be replaced by zero-emission solar-, electric-, or air-driven pumps by January 1, 2017.
The BLM believes that replacing high-bleed pneumatic controllers with low- or no-bleed controllers is a cost-effective way to reduce waste of natural gas. In most cases, this is projected to increase operators' net profits. We have heard from one company that has already voluntarily replaced all of its high-bleed pneumatic controllers because it found that the new equipment more than paid for itself within 3 to 6 months.
Under proposed § 3179.201, the BLM would require operators to replace all pneumatic controllers that have bleed rates greater than 6 scf/hour with low-bleed or no-bleed pneumatic controllers within 1 year of the effective date of the final rule. This rule would apply only to pneumatic controllers that are not subject to the EPA regulations at 40 CFR 60.5360 through 60.5390. We request comment on whether 1 year is an appropriate amount of time for compliance, and whether we should include interim deadlines for the replacement requirement such that operators must replace certain percentages of their pneumatic controllers within specified timeframes.
In § 3179.201(b), the BLM is proposing several exemptions to the replacement requirement. Like the existing EPA NSPS, this proposed rule would allow an exception to the maximum emission rate for a pneumatic controller when the operator demonstrates, and the BLM concurs, that a higher emission rate is necessary for response time, safety, and positive actuation. The proposed rule would also provide for an exception from the replacement requirement if the requirement would cause the operator to cease production and abandon significant recoverable oil reserves under the lease. In making this determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease.
In addition, under proposed § 3179.201(c), the BLM would allow an operator to retain a high-bleed pneumatic controller for up to 3 years from the effective date of the final rule, if the well or facility served by the controller has an estimated remaining productive life of no more than 3 years from the effective date of the final rule. The BLM believes the 3-year threshold represents the typical payback period for a replacement controller, given an average-cost replacement device, average reduction in waste gas, and an average value for the recovered gas. We request comment on whether this extension is needed and whether it would meaningfully reduce costs for operators with wells and facilities with remaining productive lives less than 3 years from the effective date of this rule. We also request comment on whether providing this extension would increase waste of gas and make implementation of the replacement requirement more difficult, as the actual remaining productive life of a well or facility may be longer than projected. We note that neither Colorado nor Wyoming provides for such an extension.
We estimate that the proposed pneumatic controller requirements would impact up to about 15,600 existing low-bleed pneumatic devices, and pose total costs of about $6 million per year (using a 7 percent discount rate) or $5 million per year (using a 3 percent discount rate). Because the sale of recovered gas is expected to offset the engineering costs of new controllers, the BLM expects that compliance with the pneumatic controller requirements would increase gas production by 2.9 Bcf per year, result in cost savings to the industry of about $9-11 million per year (using a 7 percent discount rate) or $11-12 million per year (using a 3 percent discount rate). On net, we project that the industry would save $3-5 million per year (using a 7 percent discount rate) or $6-7 million per year (using a 3 percent discount rate) under these requirements. These requirements are also projected to reduce methane emissions by 43,000 tpy, producing monetized benefits of $48 million per year in 2017-2019, $56 million per year in 2020-2024, and $65 million in 2025 and 2026. The resulting net benefits (including the cost savings from the value of the gas) would be $53-68 million per year (using a 7 percent discount rate) or $54-73 million per year (using a 3 percent discount rate), along with a reduction in VOC emissions of about 200,000 tpy.
For pneumatic chemical injection pumps, the BLM believes that in many instances the function performed by such a pump could be performed by a zero-emissions pump (typically solar) instead. The BLM believes that the replacement costs in these situations are relatively modest and would be at least partially offset by the value of the saved gas. Where a zero-emissions pump could not perform the function, but a flare is available on-site, the cost of routing the gas from either a chemical injection pump or a diaphragm pump to a flare is expected to be quite small.
Thus, the BLM is proposing under § 3179.202 to require the operator either: (1) To replace a pneumatic chemical injection or diaphragm pump with a zero-emissions pump; or (2) To route the pneumatic chemical injection or diaphragm pump to a flare. Under proposed § 3179.202(c), an operator would be exempt from this requirement if it demonstrates, and the BLM concurs, that: (1) There is no existing flare device on site, or routing to such a device is technically infeasible; and (2) A zero-emission pump is not a viable alternative because a pneumatic pump is necessary based on functional needs. An operator would also be exempt if the operator demonstrates, and the BLM concurs, that replacing the pneumatic pump(s) would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. This rule would apply only to pneumatic pumps that are not subject to the EPA regulations. As with pneumatic controllers, the BLM proposes that operators must replace pneumatic pumps or route to a flare device, subject to this proposed section, within 1 year of the effective date of the rule, or within 3 years of the effective date of the rule if the pneumatic pump serves a well or facility with an estimated remaining productive life of 3 years or less. We request comment on whether this extended time-period for replacement is needed or whether a shorter time-period would be sufficient. In Wyoming, pneumatic pump replacement is now required by regulation by January 1, 2017.
If the EPA finalizes its concurrent 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that the proposed requirements would impact up to 8,775 existing pumps, posing total costs of about $2.5 million per year. They would also increase gas production by 0.46 Bcf per year and result in cost savings of about $1.5-1.9 million per year (7 percent discount rate) or $1.75-2.15 million per year (3 percent discount rate). In addition, they are projected to reduce methane emissions by about 16,000 tpy, producing monetized benefits of $18 million per year in 2017-2019, $21 million per year in 2020-2024, and $24 million in 2025 and 2026. This would result in net benefits of $17 million per year in 2017-2019, $20 million per year in 2020-2024, and $23 million in 2025 and 2026, as well as reducing VOC emissions by about 4,000 tpy.
Assuming, for purposes of analysis, that EPA does not finalize the 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that the pneumatic pump requirements would affect up to about 8,775 existing pumps and about 75 new pumps per year, posing total costs of about $2.5-2.7 million per year (using 7 percent and 3 percent discount rates). They would also increase gas production by 0.5 Bcf per year and result in cost savings of about $1.5-2.2 million per year (using 7 percent and 3 percent discount rates).
In addition, they are projected to reduce methane emissions by about 16,000-17,000 tpy, producing monetized benefits of $18 million per year in 2017-2019, $22 million per year in 2020-2024, and $26 million in 2025 and 2026. This would result in net benefits of $17 million per year in 2017-2019, $21-22 million per year in 2020-2024, and $25 million in 2025 and 2026, as well as reducing VOC emissions by about 4,000 tpy.
We request comment on the practicality and costs of replacing pneumatic chemical injection and diaphragm pumps with solar pumps or routing the pump exhaust to a flare that is already installed on-site, including whether 1 year is an appropriate amount of time for compliance.
Unlike pneumatic chemical injection and diaphragm pumps, the BLM has not identified a cost-effective means to reduce gas releases from gas-assist glycol dehydrator pumps at sites that are not connected to the electric grid, and thus we are not proposing any requirements to reduce gas losses from gas-assist glycol dehydrator pumps. The BLM requests comment, however, on whether there are additional measures that could further reduce gas lost from pneumatic pumps.
Storage vessels are ubiquitous in oil and gas production. Crude oil and condensate storage vessels are designed to hold a slight back-pressure. When the pressure in the vessel exceeds the back-pressure—due to fluids being added or an increase in temperature of the vessel contents—vapors are allowed to escape, thereby equalizing the pressure inside the vessel. Released vapors are a lost source of energy and revenue, and they also represent a safety and health concern for on-site workers. In addition, these vapors, which may contain methane, ethane, and a variety of VOCs, contribute to local air pollution problems. The significance of vapor loss, in terms of energy losses, revenue losses, safety risks and environmental impacts, depends upon the volume and composition of the released vapors.
New, modified, and reconstructed storage vessels used in oil and natural gas production, natural gas processing, and natural gas transmission and storage are already subject to emissions limits under the EPA NSPS, which requires that individual storage vessels with potential to emit VOC emissions equal to or greater than 6 tpy achieve at least a 95 percent reduction in VOC emissions.
Colorado requires the capture or combustion of vapors from storage vessels with a capacity to emit 6 tpy VOC or more.
In the Upper Green River Basin, Wyoming requires that when VOC emissions from vessels or glycol dehydrators are at least 4 tpy, the operator must reduce those emissions by 98 percent.
The quantity of gas released from condensate and storage vessels depends on the throughput volumes of those vessels and how much gas is lost for a given volume of throughput. These loss rates vary depending on whether the vessel is controlled or uncontrolled and on the region of the country in which it is located. We estimate that 2.77 Bcf of natural gas was lost in 2013 from storage vessels venting on Federal and Indian lands.
Storage vessel vapors can be controlled by routing them to a flare or combustor, or by installing a VRU, which collects and compresses the vapors and returns them to the vessel or into a natural gas sales line.
Where a well facility is equipped with a flare pit or flare stack, tank vapors could be routed to that flare device. With a properly designed manifold, these flare devices can meet the 95 percent emission control standard established in the current EPA NSPS.
Combustors are enclosed devices that efficiently combust tank vapors by ensuring an optimal mix of air and flammable vapor entering the combustion chamber. Combustors meet the 95 percent emission control standard established in the existing EPA NSPS. Combustors can be sized for a specific volume of natural gas/vapors, or can be operated in series to accommodate a wide volume range. Combustors are not dependent on other equipment or operating conditions and therefore have wide applicability.
In proposing the existing NSPS rule, EPA estimated that the average operating cost of a flare device (which
VRUs meet the 95 percent emission control standard established in the EPA NSPS, and because the vapors are captured, there are no combustion emissions. Applicability of VRUs is limited by a number of conditions. VRUs require a power source, and a gas line must be available into which the controlled vapors can be directed. Due to their relatively high cost of operation (which EPA estimated at $18,900 per year in proposing its 2012 NSPS rule
Under proposed § 3179.203, the BLM would address gas losses from storage vessels that are not covered by the EPA standards for new and modified storage vessels—or, by and large, existing, unmodified storage vessels. The BLM believes that reducing venting from existing storage vessels with higher rates of venting is a reasonably cost-effective means of reducing gas losses. We also believe that rather than establishing new and separate standards for venting from existing vessels, it would be easier for operators to comply if we require existing vessels on Federal and Indian leases to meet the same standards that already apply to new, rebuilt, and modified vessels on those leases.
The aim of this proposed rule is to reduce waste of whole gas. Nevertheless, the BLM believes that it may be appropriate to express the requirements for storage vessels as a VOC standard (as a proxy) rather than a whole gas standard, as EPA and Colorado do. There is no uniform conversion factor to translate a VOC standard like that established by EPA and Colorado into a whole gas standard. The ratio of VOCs leaked to hydrocarbons leaked depends on the makeup of the gas in the particular vessel. We propose to adopt the same standard that EPA applies to new storage vessels. Specifically, the BLM proposes to require, under § 3179.203(c), that VOC emissions from existing vessels with VOC emissions equal to or greater than 6 tpy be routed to a combustion device, continuous flare, or sales line. Under proposed § 3179.203(d), these requirements would no longer apply if the uncontrolled VOC emissions fall below 4 tpy for 12 months. This proposed lower bound addresses the fact that well production, and hence gas losses from vessels, are expected to decline over time, and it is less cost-effective to require control of lower volumes of tank venting. The 6 tpy and 4 tpy thresholds are consistent with EPA regulations.
We request comments on the approach of applying EPA's new source threshold to existing storage vessels, to facilitate efficient compliance for the industry.
The proposed 6 tpy threshold tracks Colorado's standard for new storage vessels.
The BLM estimates that the proposed requirements would affect about 300 existing storage vessels on BLM-administered leases, and pose total costs of about $6 million per year (using 7 percent and 3 percent discount rates).
Over time, as well pressure in a natural gas well drops, liquids often start accumulating at the bottom of the well, which can then slow or halt gas production. Operators must remove or “unload” the liquids to maintain or restore production. Some of the methods used for liquids unloading can release substantial quantities of natural gas into the environment. In particular, operators sometimes allow the bottom hole pressure to increase and then vent or “blow down” or “purge” the well.
The amount of gas lost through liquids unloading varies substantially across regions, and also depends on whether wells are equipped with plunger lifts. We estimate that 3.26 Bcf of natural gas was lost in 2013 during liquids unloading operations on Federal and Indian lands, with 1.1 Bcf lost from wells with plunger lifts and 2.16 Bcf lost from wells without plunger lifts.
Technological developments have reduced the need for operators to unload liquids by venting a well to the atmosphere. Many companies use automated systems that rely on well pressure or timers to unload liquids using plunger lifts. More recent technology allows companies to use well data to optimize liquids unloading, a technique sometimes called “smart” automation. These “smart” systems reduce unnecessary unloading events and can dramatically cut venting from liquids unloading. For example, according to the Natural Gas STAR Report in 2006, BP reported installing plunger lifts with smart automated control systems on approximately 2,200 wells, which resulted in annual savings of 900 Mcf per well.
Advanced reservoir-energy management and optimized liquids-unloading management can reduce the frequency of well venting and the quantity of resulting emissions. These management practices can reduce venting from wells with or without plunger lifts. There are a wide variety of artificial lift systems to unload gas wells, which may be applied based on the specific mechanical conditions of the well and the conditions of the reservoir. Some of these methods are described below.
One method that can be effective when a well first exhibits signs of liquid loading is to temporarily shut-in the well to allow the pressure to increase. The well is then cycled on at a high rate to unload the well. This method is inexpensive, but as pressures in the well decline, it becomes less effective.
Using surfactants (or soap injection) is another option. With this method, a foaming agent is injected in the casing/tubing annulus by a chemical pump on a timer. The gas bubbling through the soap-water solution creates gas-water foam, which is more easily lifted to the surface for water removal. Capital and startup costs to install soap launchers range from $500-$3,880 per well.
Another option is to change the tubing in a well to smaller diameter “velocity strings.” Much like a narrowing in a river, these smaller diameter strings result in a higher fluid velocity at any given volumetric flow rate, and as a result these strings provide higher liquid lift capabilities. As reservoir pressure decreases, however, this method is less effective because of the increased friction in the smaller diameter tubing. Capital and installation costs provided from industry range from $7,000-$64,000 per well.
A plunger lift is used in conjunction with a lower-flowing tubing pressure (compression) and intermittent flow (shut-in cycle/smart automation) to lift liquids. Plungers have a wide operating range, but require a minimum gas-liquid ratio, so they are not appropriate for all applications. Plungers are most successful in low volume gas wells (
Another alternative is a gas lift, which is used to raise gas velocity in the production tubing by injecting gas down the space between the tubing and surrounding casing and combining it with gas from the reservoir to assist in lifting liquid accumulations. Gas lift typically requires additional compression and piping at the surface. The additional compression would either be electrical- or natural-gas powered, adding to emissions, complexity, reliability, and operating costs. Also, gas lift is limited to those reservoir/well combinations that are configured in such a way that the gas injected down the well will flow up the well-bore and not simply dissipate into the formation.
Finally, operators may also use artificial lifts (
Besides these measures to reduce gas losses, operators may also minimize the impact of well purging by flaring rather than venting the released gas through use of a mobile flare, but it can be difficult to separate purged gas from purged liquids.
Colorado allows an operator to vent during unloading of liquids from the wellbore only after the operator has unsuccessfully attempted to unload liquids without venting.
Recent technological developments allow liquids to be unloaded with minimal loss of gas. The BLM believes that it is reasonable to expect operators to use these available technologies to minimize gas losses, and we believe that failure to minimize losses of gas from liquids unloading should be deemed avoidable waste subject to royalties. Under proposed § 3179.204, except in specified circumstances, the BLM would prohibit new wells from unloading liquids by simply purging the well. While the BLM believes that the alternative technologies discussed above now generally make well-purging unnecessary, some of these alternatives are less costly to plan and install at the design stage, and they are therefore more appropriate for new than for existing wells. In addition, some options, such as installing an automated plunger lift, may make less sense at a well that is already nearing the end of its productive life. Thus, the BLM is proposing to limit the prohibition on well purging to new wells drilled after the effective date of this rule. We request comment on whether we should also prohibit well purging at existing wells.
In addition, under proposed § 3179.204(c), the BLM would require specified best management practices to minimize venting from liquids unloading at both new and existing wells. Specifically, the BLM proposes to require that the operator be on-site during well purging events for monitoring and reporting, unless the operator uses an automatic control system. Note that automatic control systems may vent more or less depending on the setting. We request comment on whether BLM should also require that wells with automatic control systems optimize the automatic settings so as to minimize venting.
Also, the BLM proposes under §§ 3179.204(d) and (e) to require that operators maintain certain records to document liquids unloading events.
We estimate that there are currently about 8,500 operating gas wells where gas is vented during liquids unloading. Of those wells, we estimate that about 6,950 wells (or 82 percent) are equipped with plunger lifts, while 1,550 wells (or 18 percent) are not.
Under the proposed rule, we expect most new wells would use plunger lifts for liquids unloading, except where those lifts are technically infeasible or unduly costly. Plunger lifts are already used widely,
The proposed rule would require monitoring and reporting if the operator does not use an automated system, to minimize the venting and loss of gas during liquids unloading to the minimum amount necessary to bring the well back into production. The operator may choose to install an automated system and avoid the monitoring and reporting requirements altogether. Both approaches are likely to reduce venting or loss of gas, but we are unable to estimate annual incremental production, royalty, or emissions reductions because we cannot accurately predict how many operators will choose to install an automated system.
We do not anticipate that the additional monitoring requirements would substantially increase burdens on operators, because the available data indicate that average vent times are relatively short. In the Rocky Mountain region, for example, one industry survey indicates that wells without plunger lifts vent for an average of 1.76 hours.
Since the gas wells that encounter liquids accumulation problems generally do so after well production starts to decline, the timing of any future impacts of this rule is also uncertain. The EPA's Natural Gas STAR Program has shown, however, that investing in liquids removal processes at the start of a well's decline is more successful than making similar investments later in the productive life of the well. This suggests that it is reasonable to apply a more stringent requirement for new wells drilled after the effective date of this rule, as we have proposed, but we specifically request comment on this point.
There are a range of costs for various alternatives to uncontrolled liquids unloading. The annualized cost of a plunger lift is estimated to be $1,845-$2,816 using a 7 percent discount rate or $1,788-$2,587 using a 3 percent discount rate. The annualized cost of a “smart” (or automated) plunger lift is estimated to be $2,471-$4,520 using a 7 percent discount rate or $2,303-$3,900 using a 3 percent discount rate. All estimates are in 2012 dollars and are based on an equipment life of 10 years.
We note that these cost estimates do not include sales of the recovered gas. The EPA Natural Gas STAR program information indicates that operators that install plunger lifts may experience increases in production from two effects—the capture of gas that would otherwise have been vented, and improvements in well performance due to the operation of the lifts. The gains are well-specific, but the Natural Gas STAR partners found that the additional sales of gas generally offset the costs of the lifts.
Overall, based on the experiences of the Natural Gas STAR Program partners, we would expect that the boost in well productivity and the sale of recovered gas associated with the use of plunger lifts and other well-maintenance equipment would pay for the capital costs of purchasing and installing the equipment. We request comments on this point, both in general, and specifically with respect to the proposed prohibition on the use of well purging to unload liquids from new wells.
We estimate that the proposed liquids unloading requirements would affect up to about 1,550 existing wells and about 25 new wells per year, posing total costs of about $6 million per year (using a 7 percent discount rate) or $5-6 million per year (using a 3 percent discount rate). We project that the requirements would increase gas production by roughly 2 Bcf per year, resulting in cost savings of about $7-8 million per year (using a 7 percent discount rate) or $7-10 million per year (using a 3 percent discount rate). In addition, these requirements are projected to reduce methane emissions by 30,000 to 34,000 tpy, producing monetized benefits of $33-34 million per year in 2017-2019, $41-43 million per year in 2020-2024, and $50-51 million in 2025 and 2026. Overall, we estimate that these provisions would produce net benefits of $35-52 million per year (using a 7 percent discount rate for costs and cost savings) or $35-55 million per year (using a 3 percent discount rate for costs and cost savings), and reduce VOC emissions by about 136,000 to 156,000 tpy.
Substantial quantities of gas can be lost during drilling, completion, and refracturing (often referred to as “workover”) operations. As explained in the RIA, we estimate that in 2013, up to 2.08 Bcf of natural gas was lost from these operations on BLM-administered leases. Of this, we estimate that completion emissions from hydraulically fractured oil wells accounted for 1.4 Bcf of the loss, while all other completions accounted for about 0.7 Bcf of the loss.
As discussed above, the EPA requires new hydraulically fractured and refractured gas wells to undergo green completions to capture or flare gas that otherwise would be released during drilling and completion operations. On September 18, 2015, the EPA proposed to extend these requirements to new hydraulically fractured and refractured
Proposed § 3179.101 would generally require operators to capture or flare gas generated during drilling operations. Alternatively, the operator could inject the gas or use it for production purposes. We estimate that the rule would apply to up to about 3,000 wells per year, and would contribute to the BLM's overall effort to comprehensively address associated gas venting and flaring during all phases of oil and gas production. Based on our experience in the field, the BLM believes, however, that most operators are already diverting and flaring much of the gas from drilling operations as a matter of safety and operating practice, under Onshore Oil and Gas Order No. 2. As such, we do not estimate significant costs associated with this requirement.
Proposed § 3179.102 would similarly require operators to capture or flare gas generated during well completions and well fracturing or refracturing operations. Alternatively, the operator may inject the gas or use it for production purposes.
We believe that the compliance costs associated with a requirement to flare gas would be minimal, especially for hydraulically fractured oil wells, where the equipment needed to flare is commonly already on site. We believe that operators generally direct (or may easily direct) the gas coming off of the separator to a flare pit. If this is infeasible, then the operator would likely bring a combustor to the site for the duration of the completion or direct the gases to a combustor that it would have on site to fulfill other regulatory requirements.
If the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking, as we expect, then as a practical matter, this rule's completion requirements will only impact conventional well completions, because the EPA will regulate completions of new and modified hydraulically fractured oil and gas wells. We estimate that the BLM rule would impact between 115-150 completions per year and pose costs to the industry of less than $430,000 per year. There would be only
If, for purposes of analysis, we assume that EPA does not finalize its 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that these provisions would affect about 1,250 to 1,575 completions per year and pose total costs of about $8-12 million per year (using a 7 percent discount rate) or $12 million per year (using a 3 percent discount rate). We further estimate that these provisions would increase gas production by 0.5 to 0.6 Bcf per year, resulting in cost savings of about $2 million per year (using a 7 percent discount rate) or $2-3 million per year (using a 3 percent discount rate). This would also reduce methane emissions by 11,500 to 14,500 tpy, producing monetized benefits of $13 million per year in 2017-2019, $16-18 million per year in 2020-2024, and $21-22 million in 2025 and 2026. Overall, under this scenario, these provisions are estimated to produce net benefits of $3-15 million per year (considering the present value of costs and cost savings using a 7 percent discount rate) or $3-13 million per year (considering the present value of costs and cost savings using a 3 percent discount rate), and reduce VOC emissions by 9,600 to 12,200 tpy.
The BLM requests comment on whether there are additional opportunities to reduce waste from venting through reasonable and cost-effective measures. For example, there are several categories of sources discussed in the EPA white papers and ICF studies on venting that this proposal does not currently address, including gas-assist glycol dehydrator pumps, intermittent bleed pneumatic devices, compressor stations (with respect to specific interventions that could be required), glycol dehydrators, and pipeline venting. The proposal does not currently extend to these sources for one of two reasons: Either we do not believe that the source commonly occurs on BLM-administered leases, or we are still reviewing possible approaches to reduce venting from the source. We solicit additional information on these points, and also request comments on whether any of these sources should be addressed (or addressed differently) in the final rule.
The EPA and various studies have identified operational losses (in addition to leaks) from compressors as significant sources of methane emissions, and the EPA NSPS rule establishes requirements for new and modified centrifugal wet seal compressors and reciprocating compressors.
In addition, the BLM requests comment on whether the rule should require operators to use automatic igniters on their flares and other combustion devices, and if so, under what circumstances those should be required. The proposed provisions on
Other approaches to address venting from flare malfunctions include requiring operators to install malfunction alarms with remote notification systems, and/or to use enclosed combustors rather than open flares. We request comment on whether the BLM should include these requirements as well.
In addition, the BLM requests comment on whether we should require flares to achieve a specified level of performance in eliminating venting, and if so, what level. Under the 2012 NSPS rules, EPA requires 95 percent control of VOCs from vessels and other sources, and operators may use flares to meet this standard.
As noted above in Section III.F of this preamble, the MLA's reference to applying royalties to production “removed or sold from the lease” has long been interpreted to allow for both royalty-free “unavoidable” losses of gas (see discussion above in Section IV.A.1.e of this preamble), and royalty-free on-site use of gas production (discussed here). For example, operators commonly combust a portion of the produced oil or gas to run production equipment, such as to power artificial lift equipment and drilling rigs, or to heat, separate, or dehydrate production. Operators also use gas pressure to activate pneumatic controllers and pneumatic pumps. This royalty exemption for on-site use is not unlimited, however, as the requirement to prevent waste limits royalty-free on-site use to reasonable uses that are not wasteful. Today's proposal would clarify the scope of the royalty exemption for on-site use and resolve ambiguities that have arisen under NTL-4A.
Specifically, subpart 3178 of the proposed rule would identify the oil and gas uses that would qualify for royalty-free treatment and explain related requirements. In addition, proposed § 3178.8 would specify how an operator must determine and report royalty-free volumes. Among other issues, the proposed rule addresses the following:
• Use of produced oil or gas at locations beyond the boundary of the producing lease, unit or communitized area (CA);
• Use of produced oil or gas to power equipment that the operator does not own; and
• The practice of “hot oiling,” in which oil used in the operation is not consumed.
To prevent unreasonably high royalty-free use, we considered proposing a limit, in the form of a maximum volume or maximum percentage of production. We concluded, however, that it is too difficult to identify specific volume or production percentage thresholds that would appropriately distinguish between reasonable and unreasonable quantities of on-site use. Instead, the proposed rule would directly address the royalty-free treatment of various uses of lease production and identify the situations in which prior written BLM approval would be required for royalty-free treatment of production used.
The proposed rule states that qualifying royalty-free uses must be for operations and production purposes, including placing oil and gas into marketable condition. The lessee ordinarily bears the responsibility for placing oil and gas into marketable condition at no cost to the lessor.
In addition to clarifying the scope of the royalty exemption for on-site use and resolving ambiguities that have arisen under NTL-4A, the BLM also proposes to conform its regulatory provisions governing royalty rates for new competitive leases to the corresponding rate provisions in the MLA. The MLA directs the BLM to set the royalty rate for all new competitively-issued leases “at a rate of
As noted, this proposed change would align the BLM's royalty authority with that delegated by Congress. In addition, the change would also respond to concerns expressed by the GAO and others about the adequacy of the BLM's onshore oil and gas fiscal system. In 2007 and 2008, the GAO released two reports addressing the United States' oil and gas fiscal system. The first report compared oil and gas revenues received by the Federal Government to the revenues that foreign governments receive from the development of their public oil and gas resources.
Congress did not act on the recommendation in the second GAO report, but the Department nevertheless undertook its own review. Specifically, the BLM and the BOEM contracted with the consulting firm Information Handling Services' Cambridge Energy Research Associates (IHS CERA) for a comparative assessment of the fiscal systems applicable to certain Federal, State, private, and foreign oil and gas resources (“IHS CERA Study”).
In addition to the IHS CERA Study, the BLM also reviewed a separate study conducted by industry, the “Van Meurs Study.”
In 2013, the GAO issued another report identifying specific actions for the Department to take to ensure that the Federal Government receives a fair return on the resources it manages for the American public.
In April 2015, as an initial response to these various studies and reports, the BLM published an Advance Notice of Proposed Rulemaking (ANPR) to solicit public comments and suggestions that might be used to update the BLM's regulations related to royalty rates, annual rental payments, minimum acceptable bids, and other financial measures.
The comment period on the ANPR closed on June 19, 2015. BLM received 82,074 comments, many of which were form letters, including thousands of comments from NGOs. In addition to the NGO comments, individual companies and industry trade groups, including the American Petroleum Institute, Independent Petroleum Association of America, and Western Energy Alliance, submitted comments on behalf of their members. Most of the comments focused on lease fiscal terms—royalty rates, rentals, and minimum bids.
With respect to royalty rates, comments ran the gamut from supporting increases to opposing any such changes. Commenters supporting changes to the BLM's royalty rate regulations noted that the regulations are decades old and set a rate that is generally lower then rates for comparable State and private land leases. These commenters expressed concerns about whether, in light of these facts, the BLM is obtaining a fair return for the American taxpayer from Federal oil and gas leases. A number of these commenters suggested that the BLM should, at a minimum, increase the onshore royalty rate to match the rate currently set by BOEM offshore (18.75 percent). Other commenters suggested that royalty rates should be increased in order to account for the social and environmental costs of oil and gas development.
Many commenters took the opposite view, however, opposing any changes in royalty rates and arguing that higher regulatory costs, operating costs, and uncertainty on Federal lands justify royalty rates lower than those on State and private lands. These commenters also asserted that any increase in royalty rates for Federal oil and gas leases would lead to an overall decrease in government revenue by discouraging exploration and development of Federal oil and gas resources.
Finally, some commenters offered input on alternate royalty rate structures, focusing in particular on sliding scale systems. Some commenters encouraged the BLM to consider such a system, especially a sliding scale based on market price or regional location. Other commenters were opposed to a sliding scale approach, due to perceived implementation challenges and uncertainty in reporting. These commenters also questioned the appropriateness of setting up a royalty regime in which the Federal Government shares with investors some of the risk of fluctuating gas and oil prices. Overall, most individual commenters appeared to agree generally with giving BLM the flexibility to change fiscal terms at the lease sale stage, rather than fixing royalty rates by rule.
Based on the GAO's repeated recommendations, the IHS CERA Study, the royalty rate data collected by the BLM, and the comments received in response to the ANPR—and in light of the volatile nature of oil and gas markets—the BLM has determined that its regulations should provide for maximum flexibility to adjust royalty rate terms for new competitively issued oil and gas leases. Accordingly, this proposed rule would revise the existing regulations to track statutory authority.
The BLM does not currently anticipate increasing the base royalty rate for new competitively issued leases above 12.5 percent. Before making such a change, the BLM would announce the change prior to the effective date, and would provide for a public comment period. Any proposed change would be based on relevant factors, potentially including an assessment of comparable onshore State and private fiscal systems, and an assessment of the proposed impacts of the change on Federal revenue, on production from Federal lands, and on demand for Federal oil and gas leases relative to State and private leases.
The BLM requests input on this proposed change to the royalty provisions. In particular, commenters should address the merits of the proposed change to conform to statutory language, suggest the proper factors for the BLM to consider if and when it decides to adjust royalty rates for new competitive leases, and evaluate the adequacy of the public process outlined above.
At present this is the only change the BLM proposes to make to its royalty regulations. The BLM is, however, considering a provision that would allow royalty rates on new competitively issued leases to vary after the first year, based on the lease holder's record of routine flaring of associated gas from the lease during the previous year. Implementation of such a royalty “adder” provision would involve a “look back” at each lease holder's venting and flaring activity over a 12-month period. On October 1st of each year, a lease holder would evaluate its record of routine flaring of associated gas from the lease over the prior 12-month period. If a lease holder flared above a de minimis threshold for at least 6 months of that 12-month period, then its royalty rate for the
To make this idea more concrete, suppose the BLM finalizes the proposed changes to the existing royalty provisions in 43 CFR 3103.3-1(a)(1) and (2), detailed below in the section-by-section analysis (Discussion of the Proposed Rule, V.I.1.) and laid out in the proposed regulation text.
1.
In this illustrative regulatory text, the royalty “adder” is 4 percent, and the threshold,
The purpose of the royalty adder provision would be: (1) To create an incentive for bidders to consider the availability of gas capture infrastructure and the proximity of gas processing facilities as attributes that add significant value to Federal oil development leases; and (2) To create an incentive for Federal lease holders to plan for gas capture prior to or in conjunction with the development of oil wells.
The BLM requests comment on both the concept and the implementation of the royalty adder. Would a royalty adder accomplish the purposes outlined above? If so, is the structure suggested above appropriate? Does a 4 percent adder provide adequate incentive to lease holders to plan for gas capture at the same time they plan for oil development? Is a threshold rate of 10 Mcf/producing well/day (or 300 Mcf/producing well/month) over 6 months of the previous calendar year an appropriately de minimis rate to trigger the adder? Is an annual “look back” mechanism that focuses on production over the 12 months prior to October 1 workable given how oil and gas production volumes, and flaring levels, are currently reported to ONRR, or would a different 12-month period be easier to implement? Would there be a simpler and/or more effective way to implement a royalty adder concept?
The BLM is proposing to require operators to keep records documenting their compliance with several provisions of this rule. Under proposed § 3179.8, for example, operators would need to estimate or measure all volumes of gas vented or flared, and report those volumes under applicable ONRR reporting requirements. This includes flaring of associated gas, and flaring that occurs during well drilling (proposed § 3179.101), well completions (proposed § 3179.102), initial production testing (proposed § 3179.103), and subsequent well testing (proposed § 3179.104). With respect to venting and flaring during emergencies (proposed § 3179.105), the BLM is proposing to require the operator also to estimate and report to the BLM on a Sundry Notice the volumes flared or vented beyond
In addition, with respect to venting during well maintenance and liquids unloading under proposed § 3179.204, the BLM is proposing to require operators to keep records on the cause, date, time, and duration of each venting event, as well as estimates of the quantities released. The BLM is also proposing to require operators to keep records on the dates, equipment covered, monitoring methods used, and results of the leak inspections required under proposed § 3179.305, as well as the dates that repairs are attempted, completed, and confirmed. We request comment on whether operators should be required to provide this information in an annual report, consistent with Colorado's requirements.
Currently, relatively little information on waste from venting and flaring at specific sites is directly provided to the public. The public may request information held by the BLM and ONRR through a request under the Freedom of Information Act (FOIA), but this can be more time-consuming and costly than accessing information publicly posted on Web sites.
Under existing § 3162.3-1(g), upon receiving an Application for a Permit to Drill (APD) on Federal lands, the BLM must post information for public inspection for at least 30 days before taking action. The information includes: (1) The company/operator name; (2) The well name/number; (3) The well location; and (4) Maps of the affected lands. The information must be posted in the local office of the BLM and in the appropriate surface managing agency office, if other than the BLM. Some BLM field offices also make this information available on their Web sites. The BLM has been working to upgrade its systems for accepting and processing APDs and Sundry Notices. The new APD acceptance process will allow the BLM to more easily post general information about those APDs to the Internet for public notice purposes.
With respect to venting and flaring, in some situations, such as emergencies, the operator is not currently required to provide any information to the BLM. In other situations, such as when BLM approval is required, operators typically file a Sundry Notice requesting the approval. When the BLM approves or disapproves the request, the BLM notifies the company. Neither the Sundry Notice nor the BLM disposition is currently posted, although to the extent that the information is not confidential business information, it would be available to the public through a FOIA request. Likewise, although operators are currently required to report gas vented and flared to ONRR on a lease or agreement basis, this information is currently only available to the public through a FOIA request. This information also does not include quantities of gas released through leaks or during routine operation of equipment, such as pneumatic devices.
In recent years, there has been strong and growing public interest in venting and flaring at oil and gas operations. In particular, the public has been calling for more complete, reliable, and available information on the quantities of natural gas vented and flared from BLM-administered leases. The BLM believes it is appropriate for the public to have access to information on venting and flaring from BLM-administered leases. The BLM also wants to be as responsive to reasonable public requests as possible given resource constraints.
Since at least a portion of the data on venting and flaring is already reported to and available from ONRR, the BLM believes that the least burdensome approach to increasing data access would be to expand the information that must be reported to ONRR. The goal would be to ensure that all quantities of gas vented and flared that ONRR requires to be reported are reported on ONRR's Oil and Gas Operations Report (OGOR), form ONRR-4054. Thus, the BLM proposes in §§ 3179.8 and 3179.204 to clarify the reporting requirements to ensure that operators report to ONRR measurements or estimates of all volumes of gas vented or flared. The BLM requests comment on this proposal and whether operators should report any additional information on losses of gas, such as from storage vessels or pneumatic controllers and pneumatic pumps. Several other categories of information may also generate public interest. For example, the proposed rule would require operators to provide significant new information related to plans for disposition of associated gas at the APD phase. In addition, there is already public interest in industry requests for approvals to flare and BLM responses. If this proposal is finalized, the BLM expects that there would be far fewer applications for alternative flaring limits compared to the current level of requests for approval to flare, but that there still might be substantial public interest in the applications for alternative flaring limits that BLM would receive.
To ensure transparency about the use of public resources, the BLM is considering ways to make these kinds of information publicly available online, where appropriate, without requiring interested members of the public to submit FOIA requests. The BLM requests comment on the types of data that are most useful to the public, the types of data that operators believe should remain private, and the most efficient and least burdensome approaches to making appropriate data available to the public. The BLM recognizes, however, that it must balance this interest in open government with the need to protect operators' confidential business information, and with the substantial administrative burden and costs of posting large amounts of information online.
During public outreach for the venting and flaring rule, multiple stakeholders asked the BLM to address the waste issue not only through requirements under the MLA, but also through the BLM's land-use planning and environmental review processes. Pointing to the BLM's authorities under FLPMA, procedural statutes such as the National Environmental Policy Act (NEPA), and DOI policies such as the Secretarial Orders that address climate change,
These stakeholders recommended that the BLM integrate the waste prevention provisions of the MLA with the planning and management framework informed by FLPMA and NEPA. Commenters specifically suggested that the BLM develop a new rule requiring field offices to integrate waste prevention into planning and management. More broadly, the stakeholders asked the BLM to “craft its rule to make full use of its `front end' planning and management tools” to prevent oil and natural gas waste.
Among other tools, these stakeholders suggested that resource management plans (RMP) offer an opportunity to ensure “orderly and efficient” oil and gas development by governing the scale, pace, and nature of exploration, development, and production, and by facilitating the construction of necessary infrastructure for routing captured gas to processing and storage facilities.
In addition, these stakeholders asked the BLM to use NEPA reviews to prevent methane waste. For example, they encouraged the BLM to consider methane waste from all sources in its NEPA analyses, including when considering alternatives and mitigation measures and when analyzing cumulative impacts.
Similarly, in evaluating opportunities for the BLM to reduce venting and flaring of gas, the GAO found that the agency does not as a general matter assess options for reducing venting and flaring in advance of oil and gas production. The GAO pointed out that there are two phases in advance of production where the BLM could assess venting and flaring reduction options—during the environmental review phase and when the operator applies to drill a new well. The GAO found, however, that the BLM largely fails to take advantage of these opportunities to reduce methane waste, instead using its pre-production authority solely to ensure that air quality standards are not violated. The GAO recommended that the BLM assess the potential use of venting and flaring reduction technologies to minimize the waste of natural gas in advance of production wherever applicable.
The BLM is considering the integrated approach suggested by the commenters. The BLM agrees that the land use planning and NEPA processes are important to sound oil and gas development on Federal land. Flaring sometimes results from development of oil wells in advance of gas capture infrastructure. In other cases, flaring occurs when existing gas capture and processing infrastructure is inadequate, or when operators find flaring easier or less costly than connecting to existing gas capture infrastructure. Part of the solution to flaring, therefore, is to align the timing of well development with that of capture and processing infrastructure development, and to create incentives for operators to capture rather than flare.
The land use planning and NEPA review processes could be used to achieve these improvements, but the BLM does not intend to make any changes to BLM land use planning regulations (43 CFR subparts 1601 and 1610) or to any BLM planning or NEPA guidance as part of this rulemaking. This proposed rule focuses on the requirements that apply to operators as they develop wells and produce oil and gas from lands under Federal leases (43 CFR chapter II, subparts 3178 and 3179). The regulatory changes under consideration in this rulemaking are limited to these provisions.
In response to the BLM's solicitation of stakeholder views, various stakeholders also submitted comments urging the BLM to address not only losses of natural gas from BLM-administered leases, but also losses of natural gas from facilities located in rights-of-way granted by the BLM on Federal and Indian land. As of FY 2014, the BLM had over 33,700 approved rights-of-way in place under the MLA.
In evaluating the merits of the stakeholders' suggestion, the BLM believes that relevant considerations include, among others: The quantity of gas lost from these sources, the costs and feasibility of technologies to reduce waste of gas from these sources, and the administrative burden of doing so.
Based on the currently available information, the BLM believes that there are only a small number of sources of lost gas on BLM-managed rights-of-way, and that these sources do not contribute significantly to the problem of waste. The BLM analyzed potential losses from compressors, as the likely largest sources of loss located on BLM-managed rights-of-way. There are an estimated 386 compressors located on BLM-managed rights-of-way, and most of these are believed to be small compressors used for gathering systems (as opposed to the larger compressors used for transmission pipelines). Using EPA GHG Inventory data on emissions from small compressors, the compressors located in BLM-administered rights-of-way are estimated to release approximately 47 MMcf of natural gas per year. This quantity of gas is several orders of magnitude smaller than the on-lease sources of losses on which this proposal focuses—not surprising given that the number of compressors located on BLM-administered rights-of-way is only about 4 percent of the total number of small compressors in the Rocky Mountain region (9,260), and emissions from these
Several States and tribes have worked to address concerns about venting and flaring from oil and gas production, and others are considering action on this front. The BLM believes that it is important to include in this rule a provision for recognizing highly effective State or tribal requirements that reduce flaring and/or venting as much as, or more than, the proposed rule. Under proposed § 3179.401, such State or tribal provisions could, upon BLM approval, apply in place of a provision or provisions of subpart 3179. To apply for a variance, a State or tribe would have to: Identify the specific provisions of the BLM requirements for which the variance is requested; identify the specific State or tribal regulation that would serve as a substitute; explain why the variance is needed; and demonstrate how that regulation would serve the purposes of the supplanted BLM requirements.
The relevant BLM State Director would review a State or tribal variance request and assess whether the State or tribal regulation meets or exceeds the requirements of the BLM provisions for which the State or tribe sought a variance. The proposed rule would retain the BLM's authority to rescind a variance or modify any condition of approval in a variance.
The proposed revisions to § 3103.3-1(a)(1) and (2) do four things: (1) Remove two provisions of the existing regulations that are no longer necessary (§ 3103.3-1(a)(1)(i) and (ii)); (2) Specify that the rate on all leases existing at the time the rule becomes effective would remain at the rate “prescribed in the lease or in applicable regulations at the time of lease issuance”; (3) Specify the statutory rate of 12.5 percent for all noncompetitive leases issued after the effective date of the final rule; and (4) Conform the regulatory regime for competitive leases issued after the effective date of the rule to the regime envisioned by the MLA, which specifies that the royalty rate for all new competitively issued leases be set “at a rate of not less than 12.5 percent.”
This proposed amendment to § 3160.0-5 would delete a definition of “avoidably lost” that by its terms applies to part 3160. A definition of “avoidably lost” is no longer needed for part 3160, and this definition would be superseded by the provisions in proposed subparts 3178 and 3179 governing when the loss of oil or gas is avoidable. In particular, proposed § 3179.4 delineates when the loss of oil or gas is avoidable or unavoidable.
This proposed section describes the requirements for drilling applications and plans, including specifying the information that an operator must provide with an APD. We propose to amend this section to require that when submitting an APD for a development oil well, an operator must also submit a waste minimization plan, which would not be part of the APD, and the execution of which would not be enforceable. The waste minimization plan would have to include information regarding: The pipeline infrastructure location and capacity in the area of the well or wells; the anticipated timing, quantity, and production decline curve of oil and gas production from the well or wells; a gas pipeline system location map showing the operator's wells, gas pipelines, gas processing plant(s), and proposed routes for connection to the pipeline; certification that the operator has provided one or more midstream processing companies with information about the operator's production plans, including the anticipated completion dates and gas production rates of the proposed well or wells; the volume and percentage of produced gas the operator is currently flaring or venting from wells in the same field and any wells within a 20-mile radius of that field; and an evaluation of opportunities for alternative on-site capture approaches, if pipeline transport is unavailable.
This proposed section states that the purpose of the subpart is to address circumstances in which oil and gas produced from Federal and Indian leases may be used royalty-free. This subpart would supersede those parts of NTL-4A pertaining to oil or gas used for “beneficial purposes.”
This proposed section specifies which leases, agreements, tracts, facilities, and gas lines are covered by this subpart. The proposed section also states that the term “lease” in this subpart includes IMDA agreements as consistent with those agreements and with principles of Federal Indian law—an edit intended to enhance the clarity and brevity of these provisions.
This proposed section would set forth the general rule that royalty is not due on oil or gas that is produced from a lease or CA and used for operations and production purposes (including placing oil or gas in marketable condition) on the same lease or CA without being removed from the lease or CA.
This section also addresses a similar issue with respect to unit PAs—that is, the productive areas on a unit. Units often include different PAs composed of multiple leases with varied ownership. This section would therefore limit the royalty-free use of gas from a particular PA to uses that are made on the same unit, to support production from the same unit PA. The reason for this limitation is to prevent excessive use of royalty-free gas by prohibiting a unit operator from using royalty-free production from one PA to power operations on, or treat production from, another PA on the same unit, to the benefit of different owners and to the detriment of the public interest.
Proposed § 3178.5 would qualify the general provisions of proposed § 3178.3 by listing specific operations for which prior written BLM approval would be required for royalty-free use.
This proposed section identifies uses of produced oil or gas that would not require prior written BLM approval for royalty-free treatment. The uses listed in this section involve standard and routine production and related operations. In addition, proposed paragraph (b) clarifies that the authorization to use production without payment of royalties is limited to the amount of fuel reasonably necessary to perform the operation on the lease using appropriately sized equipment. This
While the royalty-free uses proposed here are generally similar to the uses identified in the definition of “beneficial purposes” in NTL-4A, this rulemaking would clarify which uses warrant royalty-free treatment. This proposed rule would not address some uses that are defined as royalty-free under ONRR provisions, such as the royalty-free use of residue gas to fuel gas plant operations as provided in 30 CFR 1202.151(b). In addition, this proposed section would clarify that hot oil treatment is an accepted on-lease use of produced crude oil that does not require prior approval to be royalty-free. In this treatment, oil is not consumed as fuel. Rather, after the oil is pumped back into the well to stimulate production, it is produced again. Although the use of produced crude oil for hot oil treatments on the producing lease, unit, or CA has historically been understood by the BLM and by operators as a royalty-free use, it is not specifically addressed in NTL-4A.
This proposed section identifies uses of oil or gas that would require prior written BLM approval to be deemed royalty-free. The aim of this section is three-fold: (1) To ensure that the BLM retains discretion to grant royalty-free use where the BLM deems the use to be consistent with the MLA's royalty requirement for oil or gas that is produced and then removed from the lease and sold; (2) To increase uniformity in the administration of the royalty-provisions by specifying circumstances that warrant particular BLM attention; and (3) To ensure the BLM's awareness of unusual uses that risk the loss or waste of oil and gas.
For two of the identified uses, existing regulations already require BLM approval before the operator may conduct the operation. For all of the identified uses, operators would be required to submit a Sundry Notice requesting BLM approval to conduct royalty-free activities.
The potentially royalty-free uses identified in this section are as follows:
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This proposed section identifies two circumstances in which royalty-free use of oil or gas that has been moved off the lease, unit, or CA would be permitted without prior BLM approval.
The first situation is where an individual lease, unit, or CA includes non-contiguous areas, and oil or gas is piped directly from one area of the lease, unit, or CA to another area where it is used, without oil or gas being added to or removed from the pipeline, even though the oil or gas crosses lands that are not part of the lease, unit, or CA. Under this proposed section, the BLM would consider such production as not having been “removed from the lease.” This would provide the lessee or operator the same opportunity for royalty-free use as if the lease, unit, or CA were one contiguous parcel. The second situation is where a well is directionally drilled, and the wellhead is not located on the producing lease, unit, or CA, but produced oil or gas is used on the same well pad for operations and production purposes for that well. In such situations, the proposed rule would allow for royalty-free use at the well pad because, as the IBLA noted in
This proposed section would address the royalty treatment of oil or gas used in operations conducted
Paragraph (b) of this proposed section identifies circumstances in which, despite the principle articulated in paragraph (a), the BLM would consider approving off-lease royalty-free use. These include situations in which the operation is conducted using equipment or at a facility that is located off the lease, unit, or CA (under an approved permit or plan of operations, or at the agency's request) because of engineering, economic, resource protection, or physical accessibility considerations. For example, a compressor that otherwise would have been located on a lease may be sited off the lease because the topography of the lease is not conducive to equipment siting. To be approved for off-lease royalty-free use, the operation would also have to be conducted upstream of the approved FMP. This proposed
Paragraph (c) would require the operator to obtain BLM approval for off-lease royalty-free use via a Sundry Notice containing the information required under proposed section 3178.9 of this subpart. The BLM anticipates that generally such approval would be appropriate only in some of the situations in which the BLM also approves measurement at a location off the lease, unit, or CA, or when the BLM has granted approval to commingle production off the lease, unit, or CA, and to allocate production back to the producing properties.
Paragraph (d) of this proposed section would clarify that approval of off-lease measurement or commingling under other regulatory provisions does not constitute approval of off-lease royalty-free use. An operator or lessee must expressly request, and submit its justification for, approval of off-lease royalty-free use.
Paragraph (e) of this proposed section addresses circumstances in which equipment located on a lease, unit, or CA also treats production from other properties that are not unitized or communitized with the property on which the equipment is located. Unless the BLM approves off-lease royalty-free use in such situations, an operator could report as royalty-free only that portion of the oil or gas used that is properly allocable to the share of production contributed by the lease, unit or CA on which the equipment is located.
NTL-4A does not include a provision that specifically addresses approving off-lease royalty-free use. Such approval is required, however, under ONRR regulations, which provide, “All gas (except gas unavoidably lost or used on, or for the benefit of, the lease, including that gas used off-lease for the benefit of the lease when such off-lease use is permitted by the BOEMRE or BLM, as appropriate) produced from a Federal lease to which this subpart applies is subject to royalty.”
This proposed section specifies that an operator must measure or estimate the volume of royalty-free gas used in operations upstream of the FMP. In general, the operator would be free to choose whether to measure or estimate, with the exception that the operator must in all cases measure under the applicable oil or gas measurement regulations: (1) The volume of royalty-free oil used in operations on the lease, unit, or CA; and (2) The volume of royalty-free gas removed from the product downstream of the FMP and used in operations on the lease, unit, or CA. If oil is used on the lease, unit or CA, it is most likely to be removed from a storage tank on the lease, unit or CA. Thus, this proposed section would also require the operator to document the removal of the oil from the tank.
For both oil and gas, the operator would have to report the volumes measured or estimated, as applicable, under ONRR requirements.
This proposed section describes how to request BLM approval of royalty-free use when prior-approval is required under proposed § 3178.5 or proposed § 3178.7. NTL-4A is silent with respect to application procedures. This proposed section would require the operator to submit a Sundry Notice containing specified information, which is necessary for the BLM to determine if approval is appropriate. The information would include a description of the operation to be conducted, the measurement or estimation method, the volume expected to be used, the basis for an estimate (if applicable), and the proposed disposition of the oil or gas used.
This proposed section clarifies that although the operator would not be required to own the equipment in which production is used royalty-free, the operator is responsible for all authorizations, production measurements, production reporting, and other applicable requirements.
This proposed section states that the purpose of subpart 3179 would be to implement the statutes relating to prevention of waste from Federal and Indian (other than Osage Tribe) leases, conservation of surface resources, and management of the public lands for multiple use and sustained yield. The proposed section also provides that subpart 3179 would supersede those parts of NTL-4A that pertain to flaring and venting of produced gas, unavoidably and avoidably lost gas, and waste prevention.
This proposed section specifies which leases, agreements, tracts, facilities, and gas lines are covered by this subpart. The proposed section also states that the term “lease” in this subpart includes IMDA agreements as consistent with those agreements and with principles of Federal Indian law—an edit intended to enhance the clarity and brevity of these provisions.
This proposed section contains definitions for 13 terms that are used in subpart 3179: “Accessible component”; “capture” and “capture infrastructure”; “component”; “development oil well” and “development gas well”; “gas-to-oil ratio”; “gas well”; “liquid hydrocarbon”; “liquids unloading”; “lost oil or lost gas”; “storage vessel”; and “volatile organic compounds.” Some defined terms have a particular meaning in this proposed rule. Other defined terms may be familiar to many readers, but we include their definitions in the proposed regulatory text to enhance the clarity of the rule.
This proposed section describes the circumstances under which lost oil or gas would be classified as “unavoidably lost.” “Avoidably lost” oil or gas would then be defined as oil or gas that is not unavoidably lost.
NTL-4A defined the terms “avoidably lost” and “unavoidably lost,” but the definitions are general and could be applied inconsistently. The descriptions in the proposed rule are intended to enhance clarity and consistency by listing specific operations and sources that produce gas that the BLM would deem “unavoidably lost,” as long as an operator has not been negligent, has not violated laws, regulations, lease terms or orders, and has taken prudent and reasonable steps to avoid waste.
The rule would also define as “unavoidably lost” any produced gas that is vented or flared from a well that is not connected to gas capture infrastructure, if the BLM has not determined that the loss of gas through such venting or flaring is otherwise avoidable. To be deemed “unavoidably lost,” this produced gas would have to
Finally, this proposed section would define “avoidably lost” oil or gas as lost oil or gas that does not meet this section's definition of “unavoidably lost.”
This proposed section would reemphasize the distinction that is the foundation of NTL-4A: Royalties are due on all avoidably lost oil or gas, but not on unavoidably lost oil or gas. This section further provides that if oil becomes waste oil through operator negligence, the operator would owe royalties on the waste oil, but absent negligence, waste oil would be royalty-free.
This proposed section would require operators to flare all gas that is not captured, except under certain limited circumstances. Operators would be allowed to vent gas if flaring is technically infeasible—for example if the volumes of gas are too small to operate a flare, or if the gas is not readily combustible. Operators would also be allowed to vent gas in an emergency, when the loss of gas is uncontrollable or venting is necessary for safety. In addition, this proposed section would authorize venting of gas from pneumatic devices, and from storage vessels, as long as flaring of that gas is not required under other provisions of this proposed subpart.
This proposed section would impose an overall limit of 1,800 Mcf per month per well, averaged over all of the producing wells on a lease, on all venting or flaring from development oil wells, unless the BLM approves an alternative volume limit under proposed § 3179.7. This limit would phase in over the first 3 years that the rule is in effect, such that the flaring limit in year 1 would be 7,200 Mcf/well/month, averaged over all of the producing wells on a lease, the limit in year 2 would be 3,600 Mcf/well/month on average, and the limit in year 3 and thereafter would be 1,800 Mcf/well/month, again on average.
This proposed section would apply only to leases issued before the effective date of this regulation. It would allow the BLM to approve a higher limit on venting and flaring for a well, in place of the applicable limit specified in proposed § 3179.6, if the operator demonstrates, and the BLM agrees, that the limit would impose such costs as to cause the operator to cease production on the lease and abandon significant recoverable oil reserves. In making this determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease. To demonstrate the need for an alternative limit, the operator would have to submit through a Sundry Notice: (1) Information regarding the operator's wells under the lease that produce Federal or Indian gas, including identifying information, and levels of gas production, venting and flaring for each well; (2) Maps showing the lease area, well and pipeline locations, capture, flaring and venting status of wells, and distances to pipelines; (3) Information on pipeline capacity and the operator's cost projections for gas capture infrastructure and alternative methods of transportation that do not require pipelines; and (4) The operator's projections of oil and gas prices, oil and gas production volumes, costs, revenues and royalty payments from the operator's oil and gas operations on the lease over the lesser of 15 years or the remaining period in which the operator will produce from the Federal or Indian lease, unit, or CA. As provided in paragraph (c) of this proposed section, the BLM would aim to set the lowest alternative flaring limit that would not cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
In addition, this proposed section would exempt wells on a lease from the applicable flaring limit for a renewable 2-year period if the operator certifies that the following conditions apply: (1) The lease, unit, or CA is not connected to a gas pipeline; (2) The lease is more than 50 straight-line miles from the nearest gas processing plant; and (3) The rate gas flaring from the lease is 50 percent or more greater than the applicable flaring limit in proposed § 3179.6. An operator would have to submit a Sundry Notice to the BLM, certifying in an affidavit that it meets the conditions for the exemption.
This proposed section would require operators to estimate (using estimation protocols) or measure (using a metering device) all flared and vented gas, whether royalty-bearing or royalty-free.
This proposed section further provides that operators must measure rather than estimate the flared and vented volumes when the operator is flaring 50 Mcf or more of gas per day from a flare stack or manifold, based on estimated volumes.
This proposed section would not specify how to measure gas when measurement is required. Onshore Oil and Gas Orders Nos. 4 and 5, which are currently undergoing revision, contain standards for measuring royalty-bearing oil and gas, respectively.
This proposed section would also require operators to report all volumes vented or flared under applicable ONRR reporting requirements.
This proposed section would provide for a transition for operators that are operating under existing approvals for royalty-free flaring or venting, as of the effective date of the rule. Those operators could continue to flare or vent royalty-free, and/or to flare or vent above the applicable flaring limit, for 90 days after the effective date of the rule. After 90 days, those operators would become subject to all the provisions of the final rule, including both the royalty provisions and the flaring limit.
Further, this proposed section would clarify that nothing in this subpart alters the royalty-bearing status of flaring that occurred prior to [EFFECTIVE DATE OF FINAL RULE], nor the BLM's authority to determine that status and collect appropriate back-royalties.
This proposed section would clarify that nothing in this subpart alters the BLM's existing authority under the MLA to limit the volume of production from a lease, or to delay action on an APD to minimize the loss of associated gas.
This proposed section addresses certain “mixed ownership” situations, in which a single well may produce oil and gas from Federal and/or Indian mineral interests, and non-Federal, non-Indian mineral interests. This proposed section would provide that to the extent that any BLM action to enforce a prohibition, limitation, or order under this subpart adversely affects production of oil or gas from non-Federal and non-Indian mineral interests, the BLM would coordinate on a case-by-case basis with the State regulatory authority with jurisdiction over that non-Federal and non-Indian production. This is consistent with current practice, in which the BLM and State regulators coordinate closely in regulating and enforcing requirements that apply to operators producing from Federal or Indian and non-Federal non-Indian mineral interests.
This proposed section would require gas that reaches the surface as a normal part of drilling operations to be used or disposed of in one of four specified ways: (1) Captured and sold; (2) Flared at a flare pit or stack with an automatic igniter; (3) Used in the lease operations; or (4) Injected. Under the proposal, gas may not be vented except under the narrow circumstances specified in proposed § 3179.6(a).
The proposed section also addresses gas that is lost as a result of loss of well control. If there is a loss of well control, the BLM would determine whether it was due to operator negligence, and if so, the BLM will notify the operator in writing. Gas lost as a result of a loss of well control would be classified as unavoidably lost and royalty-free, unless the loss of well control was due to operator negligence, in which case it would be avoidably lost and subject to royalties.
This proposed section would address gas that reaches the surface during well completion and post-completion recovery of drilling, fracturing, or re-fracturing. It would apply the same requirements and exceptions for use, sale, or disposal as proposed for well drilling operations under proposed § 3179.101. In lieu of compliance with the requirements of this proposed section, an operator may demonstrate to the BLM that it is in compliance with the requirements for control of gas from well completions established under 40 CFR part 60 subpart OOOOa.
Volumes flared under this proposed section would be reported to ONRR as directed in proposed § 3179.106 of this subpart.
This proposed section would clarify when gas may be flared, royalty-free or otherwise, during a well's initial production test. It provides that gas may be flared royalty-free during initial production testing for up to 30 days or 20 MMcf of flared gas, whichever occurs first. Volumes flared under proposed § 3179.102(a)(2) during well completion would count towards the 20 MMcf limit. Under this section, royalty-free flaring would end when production begins.
Paragraph (b) of this proposed section would allow the BLM to approve royalty-free flaring during a longer testing period of up to 60 days, if there are well or equipment problems or a need for additional testing to develop adequate reservoir information. Paragraph (c) would allow a 90- rather than 30-day period for royalty-free flaring, during the variable and time-intensive dewatering and initial evaluation of exploratory coalbed methane well. In addition, the BLM could approve up to two extensions of 90 days each to allow for more time to dewater a coalbed methane well. The operator would have to transmit a request for a longer test period under paragraph (b) or (c) of this proposed section through a Sundry Notice. Under any of these circumstances, notwithstanding an extension of the test period, the well would be still subject to the 20 MMcf limit on flared gas.
Volumes vented or flared under this proposed section would be reported to ONRR as directed in proposed § 3179.8 of this subpart.
The proposed requirement in this section is essentially the same as NTL-4A's requirement regarding subsequent well tests. It would limit royalty-free flaring during production tests after the initial production test to 24 hours, unless the BLM approves or requires a longer test period. The operator must transmit its request for a longer test period through a Sundry Notice.
Volumes vented or flared under this proposed section would be reported to ONRR as directed in proposed § 3179.8 of this subpart.
This proposed section would provide that an operator may flare or vent royalty-free during a temporary, short-term, infrequent, and unavoidable emergency.
Paragraph (b) would limit royalty-free emergency flaring or venting to a maximum of 24 hours per incident, for a maximum of three incidents per lease, unit, or CA per 30-day period. Together, these limits restrict monthly flaring or venting to a maximum of 72 hours.
The proposed rule would further clarify that more than three failures of the same equipment within any 365-day period, and failures that result from improperly sized, installed, or maintained equipment, would not constitute an emergency. Similarly, the proposed rule would also exclude from the definition of “emergency” any equipment failure caused by operator negligence.
In addition, this proposed section would clarify that scheduled maintenance does not constitute an emergency, even when it is outside of the operator's control. For example, the fact that a downstream gas processing plant goes down for maintenance would not constitute an emergency that allows an operator to flare royalty-free.
Volumes vented or flared under this proposed section would be reported to ONRR as directed in proposed § 3179.8 of this subpart.
This proposed section would address gas losses from pneumatic controllers. Paragraph (a) identifies the pneumatic controllers that would be subject to the requirements of this section: Pneumatic controllers that use natural gas produced from a Federal or Indian lease, or from a unit or CA that includes a Federal or Indian lease, if the controllers have a continuous bleed rate greater than 6 scf/hour (“high-bleed” controllers) and are not covered by EPA
Paragraph (b) of the proposed section would require pneumatic controllers subject to the requirement to be replaced with controllers having a bleed rate of no more than 6 scf/hour. Under paragraph (c), operators would be required to replace the controllers within 1 year from the effective date of the final rule, or within 3 years from the effective date of the rule, if the well or facility served by the controller has an estimated remaining productive life of 3 years or less. Under paragraph (d), operators would also be required to ensure that pneumatic controllers are functioning within the manufacturers' specifications.
This proposed section also provides several exceptions to the replacement requirement. An operator would not be required to replace a controller if a high-bleed controller is necessary to perform the needed function. For example, replacement might not be required if a low-bleed controller would not provide a timely response, which would lead to greater waste or create a safety hazard. Likewise, replacement would not be required if the controller is routed to a flare, or if the operator demonstrates, and the BLM concurs, that replacing the pneumatic controllers on the lease would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
This proposed section would establish requirements for operators with pneumatic chemical injection pumps or pneumatic diaphragm pumps that use natural gas produced from a Federal or Indian lease, or from a unit or CA that includes a Federal or Indian lease, except those pneumatic pumps covered under EPA regulations at 40 CFR part 60, subpart OOOO. The proposed section would require operators to replace pneumatic pumps covered by this proposed section with a zero-emissions pump or route the pneumatic pump to a flare, no later than 1 year after these rules are effective.
The proposed section also provides for exceptions to the replacement requirement. An operator would not be required to replace a pneumatic pump if a zero-emissions pump would be insufficient to perform the pneumatic pump's function, and an operator would not be required to route a pneumatic pump to a flare if no flare device were available on site. Replacement or routing to a flare is also not required if the operator demonstrates, and the BLM concurs, that the cost of replacing the pneumatic pumps on the lease or routing them to a flare would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
In addition, as proposed for pneumatic controllers and based on the same rationale, this proposed section would provide that if the estimated remaining productive life of the well or facility is 3 years or less, the operator would be allowed to replace the pneumatic controller no later than 3 years from the effective date of the regulation, rather than within 1 year.
The proposed section would also require that pneumatic pumps function within manufacturers' specifications.
This proposed section addresses gas vented from an oil or condensate storage vessel (or a battery of storage vessels) that contains production from a Federal or Indian lease, or from a unit or CA that includes a Federal or Indian lease. The proposed section would require operators to route all gas vapor from covered storage vessels or batteries to a combustion device or continuous flare, or to a sales line. Operators would be required to meet this requirement no later than 6 months after the rule becomes effective.
A storage vessel would be subject to this proposed section if the vessel is not covered under EPA regulations at 40 CFR part 60 subpart OOOO, and if it has a rate of total VOC emissions equal to or greater than 6 tpy. Operators would be required to determine the rate of emissions from the storage vessel within 60 days after this rule is effective, and within 30 days after adding a new source of production to a storage vessel.
This proposed section would not apply if the total VOC emissions rate from the storage vessel declines to 4 tpy in the absence of controls for 12 consecutive months, or if the operator demonstrates, and the BLM concurs, that the cost of replacing the pneumatic pumps on the lease or routing them to a flare would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
This proposed section would establish requirements for venting and flaring during downhole well maintenance and liquids unloading. It would require the operator to use practices for such operations that maximize the recovery of gas for sale, and to flare gas that is not recoverable, unless the practices or flaring are technically infeasible or unduly costly. The proposed rule would also prohibit liquids unloading by well purging (as defined in the section) for wells drilled after the effective date of this rule, except when the operator is returning the well to production following a well workover or following a shut-in of more than 30 days.
For existing wells, before the operator purges a well for the first time after the effective date of this section, the BLM is proposing that the operator must document that purging is the only technically or economically feasible method of unloading liquids from the well. In addition, during any liquids unloading by well purging, an operator would be required to be present on site to ensure that any venting to the atmosphere is limited to what is necessary, unless the operator uses an automated control system that limits the venting event to the minimum necessary. This proposed section would require the operator to maintain records of the date and duration of each venting event and to make those records available to the BLM upon request.
Under this proposal, the operator would be required to notify the BLM by Sundry Notice within 10 days after the first liquids unloading by well purging after the effective date of the rule. Operators would also be required to notify the BLM by Sundry Notice if the cumulative duration of well purging events for a well exceeds 24 hours during any production month, or if the estimated volume of gas vented in the process exceeds 75 Mcf during any production month.
Paragraph (g) would require operators to report volumes vented during downhole maintenance and liquids unloading to ONRR.
This proposed section would apply to all oil or gas wells that produce gas from a Federal or Indian lease, or from a unit or CA that includes a Federal or Indian lease. The section would obligate operators to inspect all equipment, equipment components, facilities (such as separators, heater/treaters, and liquids unloading equipment), and compressors located on the lease, unit, or CA for leaks. Operators would be required to conduct the inspections during production operations, and to fix any leaks found.
The proposed requirement would not apply to centralized compressors, owned by a pipeline company, which the operator of the Federal or Indian lease, unit, or CA does not lease or operate, and for which the operator has no direct control over maintenance and operation. In addition, operators would have the option to demonstrate to the BLM in a Sundry Notice that, in lieu of complying with these requirements for LDAR for some or all of their equipment and facilities, the operator is complying with LDAR requirements established by the EPA under 40 CFR part 60 subpart OOOOa for the same equipment and facilities. Under the proposed rule, the BLM's LDAR requirements would apply to operators that are covered by 40 CFR part 60, but do not meet that rule's production thresholds, and are therefore exempt from performing LDAR under that rule. The BLM seeks comment on whether such operators should also be exempt from this rule's LDAR requirements.
This proposed section would prescribe the types of instruments and monitoring methods that an operator must use to inspect for leaks. Specifically, operators could use: (1) An optical gas imaging device such as an infrared camera; (2) An alternative, equally advanced monitoring device, not listed in the proposed rule, which is approved by the BLM for use by any operator; or (3) A comprehensive program, approved by the BLM, that includes the use of instrument-based monitoring devices or continuous emissions monitoring. Large operators that have 500 or more wells within the jurisdiction of a single BLM field office would have only these three choices for detecting leaks. Smaller operators, however, would have a fourth choice: To use a portable analyzer device, operated according to manufacturer specifications, and assisted by AVO inspection.
This proposed section would require operators to conduct initial site inspections within specified timeframes after the effective date of the rule. The proposed section would define “site” as a discrete area containing wellhead equipment, facilities, and compressors, which is suitable for inspection in a single visit.
The proposed section would require the operator initially to conduct site inspections twice a year. The inspection frequency would be subject to change based on whether leaks are detected in two consecutive inspections, according to the following provisions:
• Case one: If the operator detects no more than two leaks at the site inspected, in each of two consecutive semi-annual inspections, the operator could shift to conducting less frequent, annual inspections.
• Case two: If the operator detects three or more leaks at the site inspected, in each of two consecutive semi-annual inspections, the operator would have to shift to more frequent, quarterly inspections.
The proposed section also specifies that the inspection frequency would revert back to semi-annually if: (1) In case one, the operator detects three or more leaks in two subsequent, consecutive annual inspections; or (2) In case two, the operator detects no more than two leaks in two subsequent, consecutive, quarterly inspections.
Paragraph (b) of this proposed section would authorize the BLM to approve an alternative leak detection device, program, or method, if the BLM finds that the alternative would meet or exceed the effectiveness of the required approach. The operator would have to transmit a request for an alternative leak detection device, program, or method through a Sundry Notice.
Under paragraph (c), an operator would not be required to inspect components that are not accessible.
This proposed section would require operators to repair leaks within 15 calendar days of discovery of the leak, unless there is good cause for repair to take longer. The proposed rule would require the operator to notify the BLM if this occurs and to complete the repair within 15 calendar days after the cause of the delay ceases to exist. The rule would also require the operator to conduct a follow-up inspection to verify the effectiveness of the repair, using the same method used to detect the leak, within 15 calendar days after the repair and to make additional repairs within 15 calendar days if the previous repair was not effective. The repair and follow-up process would have to be followed until the repair is effective. The BLM would not consider an inspection to verify the effectiveness of a repair to be a periodic inspection under proposed § 3179.303.
This proposed section would require operators to maintain records of LDAR inspections and repairs, including dates, locations, methods, where leaks were found, dates of repairs, and dates of follow-up inspections. These records would have to be made available to the BLM upon request.
This proposed section would create a variance procedure, under which the BLM could grant a State or tribe's request to have a State or tribal regulation apply in place of a provision or provisions of this subpart. The variance request would have to: (1) Identify the specific provisions of the BLM requirements for which the variance is requested; (2) Identify the specific State or tribal regulation that would substitute for the BLM requirements; (3) Explain why the variance is needed; and (4) Demonstrate how the State or tribal regulation would satisfy the purposes of the relevant BLM provisions. The BLM State Director would review a State or tribal variance request. To approve a request, the BLM State Director would have to determine that the State or tribal regulation meets or exceeds the requirements of the provision(s) for which the State or tribe sought the variance, and that the State or tribal regulation is consistent with the terms of the affected Federal or Indian leases and applicable statutes.
Paragraph (b) would specify that the decision on a variance request is not subject to administrative appeal under 43 CFR part 4. Paragraph (c) would clarify that a variance granted under this proposed section would not constitute a variance from provisions of regulations, laws, or orders other than proposed subpart 3179. Paragraph (d) would reserve the BLM's authority to rescind a variance or modify any condition of approval in a variance.
Entities that would be directly affected by the proposed rule would include most, if not all, entities involved in the exploration and development of oil and natural gas on Federal and Indian lands. According to AFMSS data (as of March 27, 2015), there are up to 1,828 entities that currently operate Federal and Indian leases.
The potentially affected entities are likely to fall within one of the following industries, identified by the North American Industry Classification System (NAICS) codes:
Table 35 of the RIA displays 2011 data from the U.S. Census Bureau, which reveal a number of characteristics about the entities that operate within these industries.
Based on these data, in 2011, there were 6,628 entities directly involved in extraction of oil and gas in the United States, 2,041 entities involved in the drilling of wells, and 8,119 entities providing other support functions. Therefore, the approximately 17,000 entities associated with developing, and producing of domestic oil and gas
The Small Business Administration (SBA) has developed size standards to carry out the purposes of the Small Business Act and those size standards can be found in 13 CFR 121.201. For mining, including the extraction of crude oil and natural gas, the SBA defines a small entity as an individual, limited partnership, or small company, at “arm's length” from the control of any parent companies, with fewer than 500 employees. For entities drilling oil and gas wells, the threshold is also 500 employees. For entities involved in support activities, the standard is annual receipts of less than $38.5 million. Of the 6,628 domestic firms involved in oil and gas extraction, 99 percent (or 6,530) had fewer than 500 employees. There are another 2,041 firms involved in drilling. Of those firms, 98 percent of those firms had fewer than 500 employees.
To estimate a percentage for firms involved in oil and gas support activities we reference Table 36 of the RIA, which provides the NAICS information for firms involved in oil and gas support activities based on the size of receipts. The most recent data available from the U.S. Census Bureau for establishment/firm size based on receipts is for 2007. Of the 5,880 firms in oil and gas support activities in 2007, 97 percent had annual receipts of less than $35 million.
Based on this national data, the preponderance of entities involved in developing oil and gas resources are small entities as defined by the SBA. As such, a substantial number of small entities may potentially be affected by the proposed rule.
We analyzed the overall costs of the rule if the EPA finalizes the 40 CFR part 60 subpart OOOOa rulemaking, and also if the EPA does not finalize that rulemaking. As explained above, we expect more significant costs and benefits of the rule for the first few years, during which some operators would have to add or improve gas-capture capability, and some would also have to replace existing equipment. The BLM expects this transitional period to last for the first few years, after which the compliance requirements of the rule would be significantly reduced, as would any benefits associated with increased capture and sale of gas that would otherwise have been vented or flared.
Overall, assuming that the EPA finalizes its concurrent 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that this rule will pose costs ranging from $125-161 million per year (using a 7 percent discount rate) or $117-1 34 million per year (using a 3 percent discount rate) over the next 10 years.
If, for analytical purposes, we assume that EPA does not finalizes its concurrent 40 CFR part 60 subpart OOOOa rulemaking, these requirements would affect more sources and the costs would be somewhat higher. Under that scenario, the BLM estimates that this rule will pose costs ranging from $139—174 million per year (using a 7 percent discount rate) or $131-147 million per year (using a 3 percent discount rate) over the next 10 years.
In some areas, operators have already undertaken, or plan to undertake, voluntary actions to address gas losses. To the extent that operators are already in compliance with the requirements of this proposed rule, the above estimates overstate the likely impacts of the rule.
The potential benefits of the rule include the additional production of resources from Federal and Indian leases; reductions in venting, flaring, and GHG emissions; and increased opportunities for royalties.
We measure the benefits of the rule as the cost savings that the industry would receive from the recovery and sale of natural gas and the projected environmental benefits of reducing the amount of GHG and other air pollutants released into the atmosphere. As with the estimated costs, we expect benefits on an annual basis.
The estimated benefits of the rule also depend on whether the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking. Assuming that rule is in effect, the BLM estimates that this rule would result in monetized benefits of $255-329 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate) or $255-357 million per year (using a 3 percent discount rate to
If, for purposes of analysis, we assume that EPA does not finalize its 40 CFR part 60 subpart OOOOa rulemaking, we estimate that this proposed rule would result in monetized benefits of $270-354 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate) or $270-384 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate).
The proposed rule will also have numerous ancillary benefits. These include improved quality of life for nearby residents, who note that flares are noisy and unsightly at night; reduced release of VOCs, including benzene and other hazardous air pollutants; and reduced production of NOx and particulate matter, which can cause respiratory and heart problems.
Overall, the BLM estimates that the benefits of this rulemaking outweigh its costs by a significant margin. The BLM expects net benefits ranging from $115-188 million per year (using a 7 percent discount rate) or $138-232 million per year (using a 3 percent discount rate). Specifically, assuming a 7 percent discount rate, we estimate the following annual net benefits:
• $115-130 million per year from 2017-2019;
• $155-156 million per year from 2020-2024; and
• $187-188 million per year from 2025-2026.
Assuming a 3 percent discount rate, we estimate the annual net benefits would be:
• $138-151 million per year from 2017-2019;
• $192-196 million per year from 2020-2024; and
• $231-232 million per year from 2025-2026.
If, for purposes of analysis, we assume that the EPA does not finalize the 40 CFR part 60 subpart OOOOa rulemaking, we estimate the net benefits of this proposed rule would be somewhat higher, ranging from $119 million to $203 million per year (costs and costs savings calculated using a 7 percent discount rate) or $139 million to $245 million per year (costs and costs savings calculated using a 3 percent discount rate).
(a) Energy Systems
The proposed rule has a number of requirements that are expected to influence the production of natural gas, NGLs, and crude oil from onshore Federal and Indian oil and gas leases.
If subpart OOOOa were not finalized, we estimate the following incremental changes in production, noting the representative share of the total U.S. production in 2014 for context. We estimate additional natural gas production ranging from 12-15 Bcf per year (representing 0.04-0.06 percent of the total U.S. production), the productive use of an additional 29-41 Bcf of natural gas, which we estimate would be used to generate 36-51 million gallons of NGL per year (representing 0.08-0.11 percent of the total U.S. production), and a reduction in crude oil production ranging from 0.6-3.2 million bbl per year (representing 0.02-0.10 percent of the total U.S. production). Separate from the volumes listed above, we also expect 1 Bcf of gas to be combusted on-site that would have otherwise been vented. Combined, the capture or combustion of gas represents 49-52 percent of the volume vented in 2013 and the capture and/or productive use of gas represents 41-60 percent of the volume flared in 2013.
If the EPA finalizes subpart OOOOa, we estimate slightly less additional natural gas production, ranging from 11.7-14.5 Bcf per year (representing 0.04-0.05 percent of the total U.S. production in 2014), and the same amount of additional NGL production and reduced crude oil production as presented above. We also expect 0.5 Bcf of gas to be combusted on-site that would have otherwise been vented. Combined, the capture or combustion of gas represents 44-46 percent of the volume vented in 2013 and the capture and/or productive use of the gas 41-60 percent of the volume flared in 2013.
Since the relative changes in production are expected to be small, we do not expect that the proposed rule would significantly impact the price, supply, or distribution of energy.
The rule is expected to increase natural gas production from Federal and Indian leases, and likewise, is expected to increase annual royalties to the Federal Government, tribal governments, States, and private landowners. For requirements that would result in incremental gas production, we calculate the additional royalties based on that production. When considering the deferment of production that could result from the rule's flaring limit, we calculate the incremental royalty as the difference in the net present value of the royalty received 1 year later (using 7 percent and 3 percent discount rates) and the value of the royalty received now.
If subpart OOOOa is not finalized, we estimate that the rule would result in additional royalties of $9-11 million per year (discounted at 7 percent) or $11-17 million per year (discounted at 3 percent). If the EPA finalizes subpart OOOOa, we estimate additional royalties of $9-11 million per year (discounted at 7 percent) or $10-16 million per year (discounted at 3 percent).
Royalty payments are recurring income to Federal or tribal governments and costs to the operator or lessee. As such, they are private transfer payments that do not affect the total resources available to society. An important but sometimes difficult problem in cost estimation is to distinguish between real costs and transfer payments. While transfers should not be included in the economic analysis of the benefits and costs of a regulation, they may be important for describing distributional effects.
(c) Small Businesses
The BLM identified up to 1,828 entities that currently operate Federal and Indian leases. The vast majority of these entities are small business, as defined by the SBA. We estimated a range of potential per-entity costs, based on different discount rates and scenarios. Those per-entity compliance costs are presented in RIA.
Recognizing that the SBA defines a small business for oil and gas producers as one with fewer than 500 employees, a definition that encompasses many oil and gas producers, the BLM looked at company data for 26 different small-sized entities that currently hold BLM-managed oil and gas leases. The BLM ascertained the following information from the companies' annual reports to the U.S. Securities and Exchange Commission (SEC) for 2012 to 2014.
From data in the companies' 10-K filings to the SEC, the BLM was able to calculate the companies' profit margins
For these 26 small companies, a per-entity compliance cost increase of $31,400 would result in an average reduction in profit margin of 0.087 percentage points (based on the 2014 company data) and a per entity cost increase of $37,600 would result in an average reduction in profit margin of 0.105 percentage points (also based on the 2014 company data). The full detail of this calculation is available in the RIA.
Executive Order 13563 states, “Our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation.”
The proposed rule is not expected to materially impact the employment within the oil and gas extraction, drilling, and support industries. As noted previously, the anticipated additional gas production volumes represent only a small fraction of the U.S. natural gas production volumes. Additionally, the annualized compliance costs represent only a small fraction of the annual net incomes of companies likely to be impacted. Therefore, we believe that the proposed rule would not alter the investment or employment decisions of firms or significantly adversely impact employment.
The proposed requirements would require the one-time installation or replacement of equipment and the ongoing implementation of an LDAR program, both of which would require labor to comply.
This section presents the costs, benefits, net benefits, and incremental production associated with operations on Indian leases, as well as royalty implications for tribal governments.
If, as we expect, the EPA finalizes 40 CFR part 60 subpart OOOOa, we estimate that the proposed rule would pose costs ranging from $17-$23 million per year (using a 7 percent discount rate) or $16-18 million per year (using a 3 percent discount rate).
Projected benefits from the proposed rule's operation on Indian lands range from $31-39 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate) or $31-43 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate).
Net benefits from operation of the rule on leases on Indian lands range from $11-20 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate) or range from $15-27 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate).
For impacts on production from leases on Indian lands, the rule is projected to result in additional natural gas production ranging from 1.1-1.5 Bcf per year; the productive use of an additional 4.5-6.4 Bcf of natural gas, which we estimate would be used to generate 5.6-8.0 million gallons of NGL per year; and a reduction in crude oil production ranging from 0.1-0.5 million bbl per year.
We estimate additional royalties from leases on Indian lands of $1.1-1.6 million per year (discounted at 7 percent) or $1.1-1.8 million per year (discounted at 3 percent). See previous explanation about how the royalty estimates were derived.
If we assume for analytical purposes that the EPA does not finalize 40 CFR part 60 subpart OOOOa, we estimate that the proposed rule would pose costs ranging from $20-25 million per year (using a 7 percent discount rate) or from $18-21 million per year (using a 3 percent discount rate).
Projected benefits from the proposed rule's operation on Indian lands range from $35-46 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate) or $35-50 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate).
Net benefits from operation of the rule on leases on Indian lands range from $13-24 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate) or range from $17-31 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate).
With respect to production from leases on Indian lands, the rule is projected to result in additional natural gas production ranging from 1.6-2.1 Bcf per year; the productive use of an
We estimate additional royalties from leases on Indian lands of $1.4-1.9 million per year (discounted at 7 percent) or $1.4-2.1 million per year (discounted at 3 percent). See previous explanation about how the royalty estimates were derived.
Executive Order 12866 requires agencies to assess the benefits and costs of regulatory actions, and, for significant regulatory actions, submit a detailed report of their assessment to the OMB for review. A rule is deemed significant under Executive Order 12866 if it may:
(a) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities;
(b) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;
(c) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or
(d) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order.
The Office of Management and Budget has determined that this proposed rule is a significant regulatory action because it may have an annual effect on the economy of $100 million or more and because it may raise novel legal or policy issues arising out of legal mandates and the President's priorities. This proposed rule would limit flaring of associated gas from oil wells, and it would require operators to take actions to reduce gas losses through venting and leaks.
The Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act (SBREFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act, unless the head of the agency certifies that the rule would not have a significant economic impact on a substantial number of small entities.
The BLM reviewed the Small Business Administration (SBA) size standards for small businesses and the number of entities fitting those size standards as reported by the U.S. Census Bureau in the Economic Census. The BLM concludes that the vast majority of entities operating in the relevant sectors are small businesses as defined by the SBA. As such, the rule would likely affect a substantial number of small entities. The BLM believes, however, that the proposed rule would not have a significant economic impact on a substantial number of small entities. The screening analysis conducted by BLM estimates the average reduction in profit margin for small companies will be just a fraction of one percentage point, which is not a large enough impact to be considered significant.
Although it is not required, the BLM nevertheless has chosen to prepare an initial regulatory flexibility analysis for this proposed rule.
Thus, given the unique circumstances present in this rulemaking, the BLM believes it is prudent, and potentially helpful to small entities, to prepare an IRFA at this stage in the rulemaking. We do not believe this decision should be viewed as a precedent for preparing an IRFA in other rulemakings, and we may choose not to prepare a final regulatory flexibility analysis for the final rule, if our best estimate at that time is that the final rule would not have a significant economic effect on a substantial number of small entities.
Under the Unfunded Mandates Reform Act (UMRA), agencies must prepare a written statement about benefits and costs prior to issuing a proposed rule that includes any Federal mandate that is likely to result in aggregate expenditure by State, local, and tribal governments, or by the private sector, of $100 million or more in any 1 year, and prior to issuing any final rule for which a proposed rule was published.
This proposed rule does not contain a Federal mandate that may result in expenditures of $100 million or more by State, local, and tribal governments, in the aggregate, or by the private sector in any 1 year. Thus, the proposed rule is also not subject to the requirements of Section 205 of UMRA.
This proposed rule is also not subject to the requirements of Section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. It contains no requirements that apply to such governments, nor does it impose obligations upon them.
Under Executive Order 12630, the proposed rule would not have significant takings implications. A takings implication assessment is not required. The proposed rule would establish a limited set of standards
Oil and gas operators on BLM-administered leases are subject to lease terms that expressly require that subsequent lease activities be conducted in compliance with applicable Federal laws and regulations. The proposed rule is consistent with the terms of those Federal leases and is authorized by applicable statutes. Thus, the proposed rule is not a governmental action capable of interfering with constitutionally protected property rights, it would not cause a taking of private property, and it does not require further discussion of takings implications under this Executive Order.
The proposed rule would not have a substantial direct effect on the States, the relationship between the national government and the States, or the distribution of power and responsibilities among the levels of government. It would not apply to States or local governments or State or local government entities. Therefore, in accordance with Executive Order 13132, the BLM has determined that this proposed rule does not have sufficient Federalism implications to warrant preparation of a Federalism Assessment.
This proposed rule would comply with the requirements of Executive Order 12988. Specifically, this rulemaking: (a) 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 (b) Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contain clear legal standards.
In accordance with Executive Order 13175, the BLM has evaluated this rulemaking and determined that it would not have substantial direct effects on federally recognized Indian tribes. Nevertheless, on a government-to-government basis we initiated consultation with tribal governments that the proposed rule may affect.
In 2014, the BLM conducted a series of forums to consult with tribal governments to inform the development of this proposal. We held tribal outreach sessions in Denver, Colorado (March 19, 2014), Albuquerque, New Mexico (May 7, 2014), Dickinson, North Dakota (May 9, 2014), and Washington, DC (May 14, 2014).
The Paperwork Reduction Act (PRA)
This proposed rule contains information collection requirements that are subject to review by OMB under the PRA. In accordance with the PRA, the BLM is inviting public comment on proposed new information collection requirements for which the BLM is requesting a new OMB control number.
As discussed below, some provisions of the proposed rule would involve some of the information collection activities that OMB has approved under Control Number 1004-0137, Onshore Oil and Gas Operations (43 CFR part 3160) (expiration date January 31, 2018).
The information collection activities in this proposed rule are described below along with estimates of the annual burdens. Included in the burden estimates are the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing each component of the proposed information collection requirements.
The information collection request for this proposed rule has been submitted to OMB for review in accordance with the PRA. A copy of the request may be obtained from the BLM by electronic mail request to Tim Spisak at
The BLM requests comments on the following subjects:
• Whether the collection of information is necessary for the proper functioning of the BLM, including whether the information will have practical utility;
• The accuracy of the BLM's estimate of the burden of collecting the information, including the validity of the methodology and assumptions used;
• The quality, utility, and clarity of the information to be collected; and
• How to minimize the information collection burden on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other forms of information technology.
If you want to comment on the information collection requirements of this proposed rule, please send your comments directly to OMB, with a copy to the BLM, as directed in the
• Title: Waste Prevention, Production Subject to Royalties, and Resource Conservation (43 CFR parts 3160 and 3170).
• Forms: Form 3160-5, Sundry Notices and Reports on Wells.
• OMB Control Number: This is a new collection of information.
• Description of Respondents: Holders of Federal and Indian (except Osage Tribe) oil and gas leases, those who belong to federally approved units and CAs, and are parties to IMDA oil and gas agreements.
• Respondents' Obligation: Required to obtain or retain a benefit.
• Frequency of Collection: On occasion and monthly.
• Abstract: This proposed rule would update standards to reduce wasteful venting, flaring, and leaks of natural gas from onshore wells located on Federal and Indian oil and gas leases, units and CAs.
• Estimated Total Annual Burden Hours: 42,350 hours.
• Estimated Total Non-Hour Cost: None.
This proposed rule would add a new paragraph (j) to 43 CFR 3162.3-1 that would require a plan to minimize waste of natural gas when submitting an APD for a development oil well. This information would be in addition to the APD information that the BLM already collects under OMB Control Number 1004-0137. The required elements of the waste minimization plan are listed at paragraphs (j)(1) through (j)(7).
Under proposed § 3178.5, submission of a Sundry Notice (Form 3160-5) would be required to request prior written BLM approval for royalty-free treatment of volumes used for the following uses:
• Using oil as a circulating medium in drilling operations;
• Injecting gas that an operator produces from a lease, unit participating area (PA), or communitized area (CA) into the same lease, unit PA, or CA for the purpose of increasing the recovery of oil or gas (including gas that is cycled in a contained gas-lift production system), subject to an approval under 43 CFR 3162.3-2 to conduct the gas injection;
• Using oil or gas that an operator removes from the pipeline at a location downstream of the facility measurement point (FMP), if removal and use both occur on the lease, unit, or CA;
• Using gas initially removed from a lease, unit PA, or CA for treatment or processing because of particular physical characteristics of the gas, where the gas is returned to the lease, unit, or CA for lease operations; and
• Any other type of use of produced oil or gas for operations and production purposes pursuant to proposed § 3178.3 that is not identified in proposed § 3178.4.
Under proposed § 3178.7, submission of a Sundry Notice (Form 3160-5) would be required to request prior written BLM approval for off-lease royalty-free uses in the following circumstances:
• The equipment or facility in which the operation is conducted is located off the lease, unit, or CA for engineering, economic, resource-protection, or physical-accessibility reasons; and
• The operations are conducted upstream of the FMP.
Under proposed § 3178.9, the following information would be required in a request for prior approval of royalty-free use under § 3178.5, or for prior approval of off-lease royalty-free use under § 3178.7:
• A complete description of the operation to be conducted, including the location of all facilities and equipment involved in the operation and the location of the FMP;
• The method of measuring the volume of oil, or measuring or estimating the volume of gas, that the operator expects will be used in the operation, and the volume expected to be used;
• If the volume expected to be used will be estimated, the basis for the estimate (
• The proposed disposition of the oil or gas used (
Proposed § 3179.7 would apply only to leases issued before the effective date of the final rule. It would provide that an operator may seek BLM approval of venting and flaring in excess of the applicable limit under proposed § 3179.6. Using a Sundry Notice, the operator would be required to show that the applicable limit would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. To support this showing, the operator would be required to submit the following information:
• Information regarding the operator's wells under the lease that produce Federal or Indian gas, including:
○ The name, number, and location of each well, and the number of the lease, unit, or CA with which it is associated;
○ The depths and names of producing formations;
○ The gas production level of each of the operator's wells for the most recent production month for which information is available; and
○ The volumes of gas being vented and flared from each of the operator's wells;
• Map(s) showing:
○ The entire lease, unit, or CA and the surrounding lands to a distance and on a scale that shows the field in which the well is or will be located (if applicable), and all pipelines that could transport the gas from the well;
○ All of the operator's producing oil and gas wells, which are producing from Federal or Indian leases, (both on Federal or Indian leases and on other properties) within the map area;
○ Identification of all of the operator's wells within the lease from which gas is flared or vented, and the location and distance of the nearest gas pipeline(s) to each such well, with an identification of those pipelines that are or could be available for connection and use; and
○ Identification of all of the operator's wells within the lease from which gas is captured;
• Data that show pipeline capacity and the operator's projections of the cost associated with installation and operation of gas capture infrastructure and alternative methods of transportation that do not require pipelines;
• The operator's projections of gas prices, gas production volumes, gas quality (
• The operator's projections of oil prices, oil production volumes, costs, revenues, and royalty payments from the operator's oil and gas operations within the lease over the lesser of the next 15 years or the anticipated remaining period in which the operator will produce from the Federal or Indian lease, unit, or CA.
Proposed § 3179.7(d) would apply only to leases issued before the effective date of the final rule. It would authorize an operator to provide a certification in support of a renewable, 2-year exemption from volume limits (instead of an alternative limit requested under proposed § 3179.7(b)). The certification would consist of a Sundry Notice with an affidavit verifying that all of the following terms and conditions are met:
• The lease, unit, or CA is not connected to a gas pipeline;
• The closest point on the lease, unit, or CA is located more than 50 straight-line miles from the nearest gas processing plant; and
• In the most recent production month, the lease, unit or CA flared or vented at an average rate that exceeds by at least 50 percent the applicable flaring limit specified in § 3179.6.
• Proposed § 3179.102(a) would require gas that reaches the surface during well completion and related operations to be:
○ Captured and sold;
○ Directed to a flare pit or flare stack equipped with an automatic igniter to combust any flammable gasses, subject to the volumetric limitations in proposed § 3179.103(a)(3);
○ Used in operations on the lease, unit, or CA; or
○ Injected.
• Paragraph (b) would authorize an operator to demonstrate to the BLM on a Sundry Notice that it is in compliance with requirements for control of gas from well completions established under 40 CFR part 60, in lieu of compliance with the requirements of paragraph (a).
• Proposed § 3179.103 would allow gas to be flared royalty-free during a well's initial production testing until:
○ The operator determines that it has obtained adequate reservoir information for the well;
○ 30 days have passed since the beginning of the production test;
○ The operator has flared 20 million MMcf of gas; or
○ Production begins.
The BLM may extend the period for royalty-free testing, but only if the operator requests such an extension by submitting a Sundry Notice.
Proposed § 3179.104 would limit royalty-free flaring during production tests after the initial production test to 24 hours, unless the BLM approves or requires a longer test period. The operator would be allowed to request for longer test period by submitting a Sundry Notice.
Reporting of Emergency Venting and Flaring Beyond Specified Timeframes (43 CFR 3179.105)
Proposed § 3179.105 would allow an operator to flare or vent gas royalty-free during a temporary, short-term, infrequent, and unavoidable emergency for up to 24 hours per incident, and for no more than 3 emergencies within any 30-day period. The operator would be required to report on a Sundry Notice any volumes of gas flared or vented beyond those specified timeframes.
Proposed § 3179.201 addresses gas losses from pneumatic controllers that are not covered by EPA regulations at 40 CFR 60.5360 through 60.5390. The proposed section would require operators to replace pneumatic controllers that have continuous bleed rates that are greater than 6 scf/hour with lower-bleed models within 1 year after the effective date of the final rule. Paragraph (b) would provide an exception to this requirement if the operator submits a Sundry Notice to the BLM showing that:
• A pneumatic controller with a bleed rate greater than 6 scf/hour is required based on functional needs;
• The pneumatic controller exhaust is routed to a flare device; or
• The replacement of a pneumatic controller would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
Paragraph (c) would provide an exception to the replacement requirement if the operator submits a Sundry Notice showing that a pneumatic controller with a bleed rate greater than 6 scf/hour serves a well or facility has an estimated remaining productive life of 3 years or less. The operator would also be required to replace the device no later than 3 years from the effective date of the rule, absent a showing that replacement would impose costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
Proposed § 3179.202 would require operators to replace pneumatic pumps not covered under EPA regulations with zero-emissions pumps or route the pump exhaust to a flare device within 1 year after the effective date of the final rule. Paragraph (c) would provide an exception to this requirement if the operator makes a showing on a Sundry Notice, and the BLM agrees, that:
• A pneumatic pump is required based on functional needs, described in the Sundry Notice, and there is no existing flare device on site or routing to such a device is technically infeasible; or
• The installation of a zero-emissions pump would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease and there is no existing flare device on site or routing to such a device is technically infeasible.
Paragraph (d) would provide an exception to the replacement requirement if the operator submits a Sundry Notice showing that a pneumatic pump serves a well or facility that has an estimated remaining productive life of 3 years or less. The operator would also be required to replace the device no later than 3 years from the effective date of the rule, absent a showing that replacement would impose costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
Proposed § 3179.203 would require operators to route all tank vapor gas from storage vessels and batteries to a combustion device or continuous flare, or to a sales line, unless the operator submits an economic analysis in a Sundry Notice and the BLM agrees with that economic analysis. Paragraph (c) would require that the operator demonstrate in the Sundry Notice that compliance would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves. Operators would be required to submit this information no later than 6 months after the rule becomes effective.
Proposed § 3179.204 would pertain to downhole well maintenance and liquids unloading operations. Paragraph (a) would require operators to use practices that maximize the recovery of gas for sale and to flare gas that is not recovered. It would also require operators to document, before purging a well for the first time, a discovery that compliance with these requirements would be technically infeasible or unduly costly. Paragraph (d) would require that documentation to be included as part of a Sundry Notice submitted to the BLM within 10 calendar days after the first liquids unloading event by well purging conducted after the effective date of proposed § 3179.204.
Proposed § 3179.204 would pertain to downhole well maintenance and liquids unloading operations. Paragraph (e) would require an operator to notify the
Proposed §§ 3179.301 through 3179.305 would include information collection activities pertaining to the detection and repair of gas leaks during production operations. The following activities would require operators to submit a Sundry Notice:
• Proposed § 3179.301(e) would allow an operator to satisfy the requirements of proposed §§ 3179.301 through 3179.305 for some or all of the equipment or facilities on a given lease by demonstrating to the BLM on a Sundry Notice that the operator is complying with EPA requirements established pursuant to 40 CFR part 60 with respect to such equipment or facilities.
• Proposed § 3179.303(b) would allow an operator to submit a Sundry Notice requesting authorization to detect gas leaks using an alternative device, program, or method.
• Proposed § 3179.304(a) would require an operator to repair any leak not associated with normal equipment operation no later than 15 calendar days after discovery. In the event of a delay beyond 15 calendar days, paragraph (b) of this section would require the operator to submit a Sundry Notice showing good cause.
The following table details the estimated annual burdens of activities that would involve APDs and Sundry Notices, the use of which has been authorized under Control Number 1004-0137.
The following table details the annual estimated hour burdens for the rest of the proposed information collection activities in this rule.
The BLM has prepared a draft environmental assessment (EA) to determine whether issuance of this proposed regulation pertaining to oil and gas waste prevention and royalty clarification would constitute a “major Federal action significantly affecting the quality of the human environment”
During the public comment period for the proposed rule, we will consider any new information we receive that may inform our analysis of the potential environmental impacts of the rule. A copy of the draft EA can be viewed at
Under Executive Order 13211, agencies are required to prepare and submit to OMB a Statement of Energy Effects for significant energy actions. This statement is to include a detailed statement of “any adverse effects on energy supply, distribution, or use (including a shortfall in supply, price increases, and increase use of foreign supplies)” for the action and reasonable alternatives and their effects.
Section 4(b) of Executive Order 13211 defines a “significant energy action” as “any action by an agency (normally published in the
Since the compliance costs for this rule would represent such a small fraction of company net incomes, we believe that the rule is unlikely to impact the investment decisions of firms. Also, any incremental production of gas estimated to result from the rule's enactment would constitute a small fraction of total U.S. production, and any potential and temporary deferred production of oil would likewise constitute a small fraction of total U.S. production. For these reasons, we do not expect that the proposed rule would significantly impact the supply, distribution, or use of energy. As such, the rulemaking is not a “significant energy action” as defined in Executive Order 13211.
Executive Order 12866 requires each agency to write regulations that are simple and easy to understand. We invite your comments on how to make these proposed regulations easier to understand, including answers to questions such as the following:
• Are the requirements in the proposed regulations clearly stated?
• Do the proposed regulations contain technical language or jargon that interferes with their clarity?
• Does the format of the proposed regulations (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce their clarity?
• Would the regulations be easier to understand if they were divided into more (but shorter) sections?
• Is the description of the proposed regulations in the
Please send any comments you have on the clarity of the regulations to the address specified in the
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. We have developed this proposed rule in a manner consistent with these requirements.
The principal authors of this rule are: Timothy Spisak and James Tichenor of the BLM Washington Office; Eric Jones of the BLM Moab, Utah Field Office; and David Mankiewicz of the BLM Farmington, New Mexico Field Office; assisted by Faith Bremner of the staff of the BLM's Regulatory Affairs Division.
Government contracts, Mineral royalties, Oil and gas reserves, Public lands-mineral resources, Reporting and recordkeeping requirements, Surety bonds.
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, Flaring, Government contracts, Incorporation by reference, Indians-lands, Mineral royalties, Immediate assessments, Oil and gas exploration, Oil and gas measurement, Public lands—mineral resources, Reporting and recordkeeping requirements, Royalty-free use, Venting.
For the reasons set out in the preamble, the Bureau of Land Management proposes to amend 43 CFR parts 3100 and 3160 and add new subparts 3178 and 3179 to new 43 CFR part 3170 as follows:
25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359 and 1751; 43 U.S.C.
(a) Royalty on production will be payable only on the mineral interest owned by the United States. Royalty must be paid in amount or value of the production removed or sold as follows:
(1) For leases issued on or before [EFFECTIVE DATE OF THE FINAL RULE], the rate prescribed in the lease or in applicable regulations at the time of lease issuance;
(2) For leases issued after [EFFECTIVE DATE OF THE FINAL RULE]:
(i) 12
(ii) A base rate of not less than 12
(3) 16
(4) The rate used for royalty determination that appears in a lease that is reinstated or that is in force for competitive leases at the time of issuance of the lease that is reinstated, plus 4 percentage points, plus an additional 2 percentage points for each succeeding reinstatement.
(b) Leases that qualify under specific provisions of the Act of August 8, 1946 (30 U.S.C. 226(c) may apply for a limitation of a 12
(c) The average production per well per day for oil and gas will be determined pursuant to 43 CFR 3162.7-4.
(d) Payment of a royalty on the helium component of gas will not convey the right to extract the helium. Applications for the right to extract helium shall be made under 43 CFR part 16.
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.
(j) When submitting an Application for Permit to Drill an oil well, the operator must also submit a plan to minimize waste of natural gas from that well. The waste minimization plan must accompany, but would not be part of, the Application for Permit to Drill. The waste minimization plan must set forth a strategy for how the operator will comply with the requirements of 43 CFR subpart 3179 regarding control of waste from venting, flaring and leaks, and must explain how the operator plans to capture associated gas upon the start of oil production, or as soon thereafter as reasonably possible. Failure to submit a complete and adequate waste minimization plan is grounds for denying or disapproving an Application for Permit to Drill. The waste minimization plan must include the following information:
(1) The anticipated completion date of the proposed well(s);
(2) The anticipated gas production rates of the proposed well(s);
(3) A gas pipeline system location map of sufficient detail, size, and scale as to show the field in which the proposed well will be located, and all existing gas pipelines within 20 miles of the well. The map should also contain:
(i) The name and location of the gas processing plant(s) closest to the proposed well(s), and of the intended destination processing plant, if different;
(ii) The location and name of the operator of each gas pipeline within 20 miles of the proposed well;
(iii) The proposed route and tie-in point that connects or could connect the subject well to an existing gas pipeline;
(4) Information on the gas pipeline to which the operator plans to connect, including:
(i) Maximum current daily capacity of the pipeline;
(ii) Current throughput of the pipeline;
(iii) Anticipated daily capacity of the pipeline at the anticipated date of first gas sales from the proposed well;
(iv) Anticipated throughput of the pipeline at the anticipated date of first gas sales from the proposed well;
(v) Certification that the operator has provided one or more midstream processing companies with information about the operator's production plans, including the anticipated completion dates and gas production rates of the proposed well or wells; and
(vi) Any plans known to the operator for expansion of pipeline capacity for the area that includes the proposed well.
(5) A description of anticipated production, including:
(i) The anticipated date of first production;
(ii) The expected oil and gas production rates and duration from the proposed well. If the proposed well is on a multi-well pad, the plan should include the total expected production for all wells being completed;
(iii) The expected production decline curve of both oil and gas from the proposed well; and
(iv) The expected Btu value for gas production from the proposed well.
(6) The volume and percentage of produced gas the operator is currently flaring or venting from wells in the same field and any wells within a 20-mile radius of that field; and
(7) An evaluation of opportunities for alternative on-site capture approaches, if pipeline transport is unavailable.
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 purpose of this subpart is to address the circumstances under which oil or gas produced from Federal and Indian leases may be used royalty-free in operations on the lease, unit, or communitized area (CA). This subpart supersedes those portions of Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-4A), 44 FR 76600 (December 27, 1979), pertaining to oil or gas used for beneficial purposes.
(a) This subpart applies to:
(1) All onshore Federal and Indian (other than Osage Tribe) oil and gas leases, units, and CAs, except as otherwise provided in this subpart;
(2) Indian Mineral Development Act (IMDA) oil and gas agreements, unless specifically excluded in the agreement or unless the relevant provisions of this subpart are inconsistent with the agreement;
(3) Leases and other business agreements and contracts 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;
(4) Committed State or private tracts in a federally approved unit or communitization agreement defined by or established under 43 CFR subpart 3105 or 43 CFR part 3180;
(5) All onshore wells, tanks, compressors, and other facilities located on a Federal or Indian lease or a federally approved unit or CA; and
(6) All gas lines located on a Federal or Indian lease or federally approved unit or CA that are owned or operated by the operator of the lease, unit, or communitization agreement.
(b) For purposes of this subpart, the term “lease” also includes IMDA agreements.
(a) To the extent specified in §§ 3178.4 and 3178.5, royalty is not due on:
(1) Oil or gas that is produced from a lease or CA and used for operations and production purposes (including placing oil or gas in marketable condition) on the same lease or CA without being removed from the lease or CA; or
(2) Oil or gas that is produced from a unit PA and used for operations and production purposes (including placing oil or gas in marketable condition) on the unit, for the same unit PA, without being removed from the unit.
(a) For the uses described in § 3178.5, the operator must obtain prior written BLM approval for the volumes used for operational and production purposes to be royalty free.
(a) Uses of produced oil or gas for operations and production purposes that do not require prior written BLM approval for the used volumes to be treated as royalty free under § 3178.3 are:
(1) Use of fuel to power artificial lift equipment;
(2) Use of fuel to power equipment used for enhanced recovery;
(3) Use of fuel to power drilling rigs;
(4) Use of gas to actuate pneumatic controllers or operate pneumatic pumps at production facilities;
(5) Use of fuel to heat, separate, or dehydrate production;
(6) Use of fuel to compress gas to place it in marketable condition; and
(7) Use of oil that an operator produces from a lease, unit, or CA and pumps into a well on the same lease, unit, or CA to clean the well and improve production,
(b) The volume to be treated as royalty free must not exceed the amount of fuel reasonably necessary to perform the operational function, using equipment of appropriate capacity.
(a) Uses that require prior written approval from the BLM before the production used may be treated as royalty free under § 3178.3 include: (1) Using oil as a circulating medium in drilling operations;
(2) Injecting gas that an operator produces from a lease, unit PA, or CA into the same lease, unit PA, or CA for the purpose of increasing the recovery of oil or gas (including gas that is cycled in a contained gas-lift production system), subject to an approval under 3162.3-2 of this title to conduct the gas injection;
(3) Using oil or gas that an operator removes from the pipeline at a location downstream of the Facility Measurement Point (FMP), if removal and use both occur on the lease, unit, or CA;
(4) Using gas initially removed from a lease, unit PA, or CA for treatment or processing because of particular physical characteristics of the gas, where the gas is returned to the lease, unit, or CA for lease operations; and
(5) Any other type of use of produced oil or gas for operations and production purposes pursuant to § 3178.3 that is not identified in § 3178.4.
(b) (1) The operator must obtain BLM approval to conduct activities under paragraph (a) of this section by submitting a Form 3160-5, Sundry Notices and Reports on Wells (Sundry Notice) containing the information required under § 3178.9.
(2) With respect to uses under paragraph (a)(3) of this section, the operator must measure the volume of oil or gas used in accordance with Onshore
(3) With respect to uses under paragraph (a)(4) of this section, the operator must measure any gas returned to the lease, unit, or CA under such an approval in accordance with Onshore Oil and Gas Order No. 5 or other successor regulations.
(c) If the BLM disapproves a request for royalty-free treatment for volumes used under this section, the operator must pay royalties for the gas used beginning on the date the operator was required to request approval under paragraph (a) of this section.
Oil or gas used after being moved off the lease, unit, or CA may be treated as royalty free without prior written BLM approval only if the use meets the criteria under § 3178.4 and when:
(a) Oil or gas is piped along a logical route, based on existing access, topography, land ownership or other similar characteristic, directly from one area of the lease, unit, or CA to another area of the same lease, unit, or CA where it is used without oil or gas being added to or removed from the pipeline while crossing lands that are not part of the lease, unit, or CA; or
(b) A well is directionally drilled and the wellhead is not located on the producing lease, unit, or CA, and oil or gas is used on the same well pad for operations and production purposes for that well.
(a) Except as provided in § 3178.6(b) and paragraph (b) of this section, royalty is owed on all oil or gas used in operations conducted off the lease, unit, or CA.
(b) The BLM may grant prior written approval to treat oil or gas used in operations conducted off the lease, unit, or CA as royalty free (referred to as off-lease royalty-free use) if the use meets one or more of the criteria listed in § 3178.5(a) and if:
(1) The equipment or facility in which the operation is conducted is located off the lease, unit, or CA for engineering, economic, resource-protection, or physical-accessibility reasons; and
(2) The operations are conducted upstream of the FMP.
(c) The operator must obtain BLM approval under paragraph (b) of this section by submitting a Sundry Notice containing the information required under § 3178.9.
(d) Approval of measurement or commingling off the lease, unit, or CA under other regulations does not constitute approval of off-lease royalty-free use. The operator or lessee must expressly request, and submit its justification for, approval of off-lease royalty-free use.
(e) If equipment or a facility located on a particular lease, unit, or CA treats oil or gas produced from properties that are not unitized or communitized with the property on which the equipment or facility is located, in addition to treating oil or gas produced from the lease, unit, or CA on which the equipment or facility is located, the operator may report as royalty free only that portion of the oil or gas used as fuel that is properly allocable to the share of production contributed by the lease, unit, or CA on which the equipment is located, unless otherwise authorized by the BLM under this section.
(a) The operator must measure or estimate the volumes of royalty-free gas used in operations upstream of the FMP.
(b) The operator must measure all gas that is removed from the product stream downstream of the FMP and used in operations on the lease, unit, or CA (or off the lease, unit, or CA if the BLM approves such use), using the measurement procedures in Onshore Oil and Gas Order No. 5 or other successor regulation.
(c) The operator must measure the volume of oil used in operations on the lease, unit, or CA (or off the lease, unit, or CA if the BLM approves such use) using the measurement procedures in Onshore Oil and Gas Order No. 4 or other successor regulation. The operator must also document removal of such oil from the tank or pipeline.
(d) Each of the volumes required to be measured or estimated, as applicable, under this subpart, must be reported by the operator following applicable ONRR reporting requirements.
To request written approval of royalty-free use when required under § 3178.5, or of off-lease royalty-free use under § 3178.7, the operator must submit a Sundry Notice that includes the following information:
(a) A complete description of the operation to be conducted, including the location of all facilities and equipment involved in the operation and the location of the FMP;
(b) The volume of oil or gas that the operator expects will be used in the operation, and the method of measuring or estimating that volume;
(c) If the volume of gas expected to be used will be estimated, the basis for the estimate (
(d) The proposed disposition of the oil or gas used (
The operator is not required to own or lease the equipment or facility that uses oil or gas royalty free. The operator is responsible for obtaining all authorizations, measuring production, reporting production, and all other applicable requirements.
The purpose of this subpart is to implement and carry out the purposes of statutes relating to prevention of waste from Federal and Indian (other than Osage Tribe) leases, conservation of surface resources, and management of the public lands for multiple use and sustained yield. This subpart supersedes those portions of Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-4A), 44 FR 76600 (December 27, 1979), pertaining to, among other things, flaring and venting of produced gas, unavoidably and avoidably lost gas, and waste prevention.
(a) This subpart applies to:
(1) All onshore Federal and Indian (other than Osage Tribe) oil and gas leases, units, and CAs, except as otherwise provided in this subpart;
(2) IMDA oil and gas agreements, unless specifically excluded in the agreement or unless the relevant provisions of this subpart are inconsistent with the agreement;
(3) Leases and other business agreements and contracts 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;
(4) Committed State or private tracts in a federally approved unit or communitization agreement defined by
(5) All onshore wells, tanks, compressors, and other facilities located on a Federal or Indian lease or a federally approved unit or CA; and
(6) All gas lines located on a Federal or Indian lease or federally approved unit or CA that are owned or operated by the operator of the lease, unit, or communitization agreement.
(b) For purposes of this subpart, the term “lease” also includes IMDA agreements.
As used in this subpart, the term:
For purposes of this subpart:
(a) “Unavoidably lost” oil or gas means lost oil or gas where the operator has not been negligent, and has complied fully with applicable laws, lease terms, regulations, provisions of a previously approved operating plan, or other written orders of the BLM, including:
(1) Produced oil or gas that is lost from the following operations or sources and cannot be recovered in the normal course of operations, where the operator has taken prudent and reasonable steps to avoid waste:
(i) Well drilling;
(ii) Well completion and related operations;
(iii) Initial production tests, subject to the limitations in § 3179.103;
(iv) Subsequent well tests, subject to the limitations in § 3179.104;
(v) Exploratory coalbed methane well dewatering;
(vi) Emergencies, subject to the limitations in § 3179.105;
(vii) Evaporation from storage vessels;
(viii) Downhole well maintenance;
(ix) Liquids unloading;
(x) Leaks; and
(xi) Releases from pneumatic controllers and pumps; or
(2) Produced gas that is flared or vented from a well that is not connected to gas capture infrastructure, absent a BLM determination that the loss of gas through such venting or flaring is otherwise avoidable, subject to the limitations in § 3179.6.
(b) “Avoidably lost” oil or gas means lost oil or gas that is not unavoidably lost as defined in paragraph (a) of this section.
(a) Royalty is due on:
(1) All avoidably lost oil or gas; and
(2) Waste oil that became waste through operator negligence.
(b) Royalty is not due on:
(1) Unavoidably lost oil or gas; and
(2) Waste oil that did not become waste through operator negligence.
(a) The operator must flare rather than vent any gas that is not captured except:
(1) When flaring the gas is technically infeasible, such as when the gas is not readily combustible or the volumes are too small to flare;
(2) Under emergency conditions when the loss of gas is uncontrollable or venting is necessary for safety, subject to § 3179.105;
(3) When § 3179.203 does not require the combustion or flaring of gas vapors from storage vessels; or
(4) When the gas is vented through operation of a natural gas-activated pneumatic controller or pump.
(b) Except as provided in § 3179.7, an operator must not flare or vent gas in excess of the following amounts, representing the total volume of gas flared or vented over a production month from all development oil wells on a lease, unit, or CA, divided by the number of development oil wells contributing production for at least 10 days during that month:
(1) 7,200 Mcf, for each month during the period from [EFFECTIVE DATE OF FINAL RULE] until [1 YEAR AFTER EFFECTIVE DATE OF FINAL RULE];
(2) 3,600 Mcf, for each month during the period from [1 YEAR AFTER EFFECTIVE DATE OF FINAL RULE] until [2 YEARS AFTER EFFECTIVE DATE OF FINAL RULE]; and
(3) 1,800 Mcf, for each month thereafter.
(a) With respect to leases issued before the effective date of this regulation, the BLM may approve an alternative rate-based limit on venting and flaring from a lease, unit, or CA that is flaring at a rate that exceeds the applicable limit under § 3179.6, if the
(b) To support such a demonstration, the operator must submit a Sundry Notice that includes the following information:
(1) Information regarding the operator's wells under the lease that produce Federal or Indian gas, including:
(i) The name, number, and location of each well, and the number of the lease, unit, or CA with which it is associated;
(ii) The depths and names of producing formations;
(iii) The gas production level of each of the operator's wells for the most recent production month for which information is available; and
(iv) The volumes of gas being vented and flared from each of the operator's wells;
(2) Map(s) showing:
(i) The entire lease, unit, or CA and the surrounding lands to a distance and on a scale that shows the field in which the well or wells are or will be located (if applicable), and all pipelines that could transport the gas from the well or wells;
(ii) All of the operator's producing oil and gas wells, which are producing from Federal or Indian leases (both on Federal or Indian leases and on other properties) within the map area;
(iii) Identification of all of the operator's wells within the lease from which gas is flared or vented, and the location and distance of the nearest gas pipeline(s) to each such well, with an identification of those pipelines that are or could be available for connection and use; and
(iv) Identification of all of the operator's wells within the lease from which gas is captured;
(3) Data that show pipeline capacity and the operator's projections of the cost associated with installation and operation of gas capture infrastructure and alternative methods of transportation that do not require pipelines;
(4) The operator's projections of gas prices, gas production volumes, gas quality (
(5) The operator's projections of oil prices, oil production volumes, costs, revenues, and royalty payments from the operator's oil and gas operations within the lease over the lesser of:
(i) The next 15 years; or
(ii) The anticipated remaining period in which the operator will produce from the Federal or Indian lease, unit, or CA.
(c) In establishing an alternative volume limit on venting and flaring under this section, the BLM will aim to set the limit at the lowest level that the BLM determines, considering the information identified in paragraph (b) of this section, will not cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
(d) Instead of an alternative limit under paragraph (a) of this section, a lease issued before the effective date of this regulation will receive a renewable, 2-year exemption from the applicable flaring limit specified in § 3179.6 if the authorizing officer verifies that all of the following terms and conditions are met:
(i) The lease, unit, or CA is not connected to a gas pipeline;
(ii) The closest point on the lease, unit, or CA is located more than 50 straight-line miles from the nearest gas processing plant;
(iii) In the most recent production month, the lease, unit or CA flared or vented at an average rate that exceeds by at least 50 percent the applicable flaring limit specified in § 3179.6; and
(iv) The operator submits to the BLM a Sundry Notice with an affidavit certifying that it meets the conditions in paragraphs (d)(i) through (iii) of this section.
(a) The operator must estimate or measure all volumes of gas vented or flared from wells, and report those volumes under applicable ONRR reporting requirements, including 30 CFR part 1210.
(b) The operator may choose whether to estimate or measure such volumes, except that measurement is required:
(1) If the operator estimates that the volume of gas vented or flared from a flare stack or manifold equals or exceeds 50 Mcf per day; or
(2) If the BLM determines and informs the operator that the additional accuracy offered by measurement is necessary for effective implementation of this subpart.
(a) Approvals to flare or vent royalty free, and/or to flare or vent at a level above the 7,200 Mcf per month limit in § 3179.6(b)(1), which are in effect as of the effective date of this rule, will continue in effect until [90 DAYS AFTER EFFECTIVE DATE OF THE FINAL RULE].
(b) The provisions of this subpart do not affect any determination made by the BLM before or after [EFFECTIVE DATE OF FINAL RULE], with respect to the royalty-bearing status of flaring that occurred prior to [EFFECTIVE DATE OF FINAL RULE].
(a) If production from an oil well newly connected to a gas pipeline results or is expected to result in one or more producing wells already connected to the pipeline being forced off the line, the BLM may exercise existing authority to limit the production level from the new well until the pressure of gas production from the new well stabilizes at levels that allow transportation of gas from all wells connected to the line.
(b) If gas capture capacity is not yet available on a given lease, the BLM may exercise existing authority to delay action on the APD for that lease, or approve the APD with conditions for gas capture or limitations on production. If the lease for which the APD is submitted is not yet producing, the BLM may direct or grant a lease suspension under 43 CFR 3103.4-4.
To the extent that any BLM action to enforce a prohibition, limitation, or order under this subpart adversely affects production of oil or gas that comes from non-Federal and non-Indian mineral interests, the BLM will coordinate, on a case-by-case basis, with the State regulatory authority having jurisdiction over the oil and gas production from the non-Federal and non-Indian interests.
(a) Except as provided in § 3179.6(a) of this subpart, gas that reaches the surface as a normal part of drilling operations must be:
(1) Captured and sold;
(2) Directed to a flare pit or flare stack equipped with an automatic igniter to combust any flammable gasses;
(3) Used in operations on the lease, unit, or CA; or
(4) Injected.
(b) If gas is lost as a result of loss of well control, the BLM will make a determination of whether the loss of well control is due to operator negligence. Such gas is avoidably lost if the BLM determines that the loss of well
(a) Except as provided in § 3179.6(a), gas that reaches the surface during well completion and post-completion, drilling fluid recovery, or fracturing or refracturing fluid recovery operations must be:
(1) Captured and sold;
(2) Directed to a flare pit or flare stack equipped with an automatic igniter to combust any flammable gasses, subject to the volumetric limitations in § 3179.103(a)(3);
(3) Used in operations on the lease, unit, or CA; or
(4) Injected.
(b) In lieu of compliance with the requirements of paragraph (a) of this section, an operator may demonstrate to the BLM on a Sundry Notice that it is in compliance with the requirements for control of gas from well completions established under 40 CFR part 60, subpart OOOOa.
(a) Gas flared during a well's initial production test is royalty-free under §§ 3179.4(a)(1)(iii) and 3179.5(b) of this subpart until one of the following occurs:
(1) The operator determines that it has obtained adequate reservoir information for the well;
(2) 30 days have passed since the beginning of the production test, except as provided in paragraph (b) and paragraph (c) of this section;
(3) The operator has flared 20 million cubic feet (MMcf) of gas, when volumes flared under this section are combined with volumes flared under § 3179.102(b); or
(4) Production begins.
(b) The BLM may extend the period specified in paragraph (a)(2) not to exceed an additional 60 days, based on testing delays caused by well or equipment problems or if there is a need for further testing to develop adequate reservoir information.
(c) During the dewatering and initial evaluation of an exploratory coalbed methane well, the 30-day period specified in paragraph (a)(2) of this section is extended to 90 days. The BLM may approve up to two extensions of this evaluation period, of up to 90 days each.
(d) The operator must submit its request for a longer test period under paragraph (b) or (c) of this section using a Sundry Notice.
During well tests subsequent to the initial production test, the operator may flare gas for no more than 24 hours royalty free under §§ 3179.4(a)(1)(iv) and 3179.5(b) of this subpart, unless the BLM approves or requires a longer period. If the operator requests a longer period, it must submit a Sundry Notice.
(a) An operator may flare or, if flaring is not feasible given the emergency, vent gas royalty-free under § 3179.6(a) of this subpart during a temporary, short-term, infrequent, and unavoidable emergency.
(b) The operator may flare or vent gas royalty free for up to 24 hours per incident (unless the BLM extends the period), and for no more than three emergencies for a lease, unit, or CA within any 30-day period.
(c) The following do not constitute emergencies under this section:
(1) More than 3 failures of the same equipment within any 365-day period;
(2) The operator's failure to install appropriate equipment of a sufficient capacity to accommodate the volume of gas being produced;
(3) Failure to limit production when the production rate exceeds the capacity of the related equipment, pipeline, or gas plant, or exceeds sales contract volumes of oil or gas;
(4) Scheduled maintenance; or
(5) Operator negligence.
(d) The operator must estimate and report to the BLM on a Sundry Notice the volumes flared or vented beyond the timeframes specified in paragraph (b) of this section.
(a) A pneumatic controller that uses natural gas produced from a Federal or Indian lease, or from a unit or CA that includes a Federal or Indian lease, is subject to this section if the pneumatic controller:
(1) Has a continuous bleed rate greater than 6 standard cubic feet (scf) per hour; and
(2) Is not subject to 40 CFR 60.5360 through 60.5390.
(b) The operator must replace a pneumatic controller subject to this section with a pneumatic controller having a bleed rate of 6 scf per hour or less within the timeframes set forth in paragraph (c) of this section, unless:
(1) The operator notifies the BLM through a Sundry Notice that use of a pneumatic controller with a bleed rate greater than 6 scf per hour is required based on functional needs described in the Sundry Notice, that may include, but are not limited to, response time, safety, and positive actuation;
(2) The operator notifies the BLM through a Sundry Notice that the pneumatic controller exhaust is routed to a flare device; or
(3) The operator notifies the BLM through a Sundry Notice and demonstrates, and the BLM agrees, based on the information identified in § 3179.7(b), that replacement of a pneumatic controller subject to paragraph (a)(1)(i) of this section would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
(c) The operator must replace the pneumatic controller(s) no later than 1 year after the effective date of this section as required under paragraph (b) of this section, except that if the well or facility that the pneumatic controller serves has an estimated remaining productive life of 3 years or less from the effective date of this section, the operator must notify the BLM through a Sundry Notice and replace the pneumatic controller no later than 3 years from the effective date of this section.
(d) The operator must ensure pneumatic controllers are functioning within manufacturers' specifications.
(a) A pneumatic chemical injection or pneumatic diaphragm pump is subject to this section if it:
(1) Uses natural gas produced from a Federal or Indian lease, or from a unit or CA that includes a Federal or Indian lease; and
(2) Is not subject to 40 CFR part 60, subpart OOOOa.
(b) The operator must replace a pneumatic pump subject to this paragraph with a zero-emissions pump or route the pump to a flare device within the timeframes set forth in paragraph (d) of this section.
(c) The requirement in paragraph (b) of this section does not apply if:
(1) The operator notifies the BLM through a Sundry Notice that:
(i) Use of a pneumatic pump is required based on functional needs, described in the Sundry Notice; and
(ii) There is no existing flare device on site or routing to such a device is technically infeasible; or
(2) The operator submits a Sundry Notice to the BLM that:
(i) Provides an economic analysis that demonstrates, and the BLM agrees,
(ii) Demonstrates to the BLM that there is no existing flare device on site or routing to such a device is technically infeasible.
(d) The operator must replace the pneumatic pump(s) or connect to a flare device no later than 1 year after the effective date of this section, except that if the well or facility that the pneumatic pump serves has an estimated remaining productive life of 3 years or less from the effective date of this section, the operator must notify the BLM through a Sundry Notice and replace the pneumatic pump no later than 3 years from the effective date of this section.
(e) The operator must ensure pneumatic pumps are functioning within manufacturers' specifications.
(a) A crude oil or condensate storage vessel is subject to this section if the vessel:
(1) Contains production from a Federal or Indian lease, or from a unit or CA that includes a Federal or Indian lease;
(2) Is not subject to 40 CFR part 60, subpart OOOO; and
(3) Has a rate of total VOC emissions equal to or greater than 6 tons per year (tpy).
(b) The operator must determine the rate of emissions from the storage vessel within 60 days after the effective date of this section, and within 30 days after any new source of production is added to the tank.
(c) No later than 6 months after the effective date of this section, the operator must route all tank vapor gas from a storage vessel that is subject to this section to a combustion device or continuous flare, or to a sales line unless the operator submits an economic analysis to the BLM through a Sundry Notice that demonstrates, and the BLM agrees, based on the information identified in § 3179.7(b), that compliance with this requirement would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.
(d) If the rate of total uncontrolled gas release from a storage vessel declines to 4 tpy or less for any continuous 12 month period, the requirements of this section no longer apply.
(a) During downhole well maintenance and liquids unloading operations, the operator must use practices that maximize the recovery of gas for sale and must flare gas not recovered except where such practices or flaring are technically infeasible or unduly costly. Before the operator purges a well for the first time after the effective date of this section, the operator must document that other methods are technically infeasible or unduly costly, and provide that information as part of the Sundry Notice required under paragraph (d) of this section.
(b) For wells drilled after the effective date of this section, the operator may not conduct liquids unloading by well purging, except where the operator is returning a well to production following a well workover or following a shut-in for more than 30 days.
(c) For any liquids unloading by well purging, the operator must:
(1) Be present on-site throughout the event to ensure that any venting to the atmosphere is limited to no more than what is practically necessary, unless the operator uses an automatic control system that relies on real-time pressure or flow, timers, or other well data to minimize venting;
(2) Record the cause, date, time, duration, and estimated volume of each venting event; and
(3) Maintain the liquids unloading records for the period required under § 3162.4-1 of this title and make them available to the BLM, upon request.
(d) The operator must notify the BLM by Sundry Notice within 10 calendar days after the first liquids unloading event by well purging conducted after the effective date of this section. This requirement applies to each well the operator operates.
(e) The operator must notify the BLM by Sundry Notice, within 14 calendar days, if:
(1) The cumulative duration of well purging events for a well exceeds 24 hours during any production month; or
(2) The estimated volume of gas vented in liquids unloading by well purging operations for a well exceeds 75 Mcf during any production month.
(f) For purposes of this section, “well purging” means blowing accumulated liquids out of a wellbore by gas pressure where the gas is vented to the atmosphere.
(g) Total estimated volumes vented as a result of downhole well maintenance and liquids unloading during the production month must be included in volumes reported to ONRR as vented.
(a) The requirements of §§ 3179.301 through 3179.305 of this subpart apply to all wells that produce natural gas from a Federal or Indian lease, or from a unit or CA that includes a Federal or Indian lease, including oil wells that also produce natural gas.
(b) The operator is responsible, as prescribed in §§ 3179.302 and 3179.303 of this subpart, to inspect for gas leaks on the following:
(1) All equipment and equipment components at the wellhead;
(2) All facilities that the operator operates; and
(3) All compressors located on the lease, unit, or CA that the operator owns, leases, or operates.
(c) All leak inspections must occur during production operations.
(d) The operator must fix the leaks as prescribed in §§ 3179.304 and 3179.305 of this subpart. See 43 CFR 3162.5-1 for responsibility to repair oil leaks.
(e) An operator may satisfy the requirements of §§ 3179.301 through 3179.305 for some or all of the equipment or facilities on a given lease by demonstrating to the BLM on a Sundry Notice that the operator is complying with LDAR requirements established under 40 CFR part 60, subpart OOOOa with respect to such equipment or facilities.
(a) The operator must use one or more of the following instruments or monitoring methods to detect leaks:
(1) An optical gas imaging device;
(2) A monitoring device not listed in this section, which is approved by the BLM for use by any operator, under § 3179.303(b) of this subpart;
(3) A comprehensive program, approved by the BLM under § 3179.303(b) of this subpart, that includes the use of instrument-based monitoring devices; or
(4) A portable analyzer device capable of detecting leaks, such as catalytic oxidation, flame ionization, infrared absorption or photoionization devices, operated according to manufacturer specifications, and assisted by audio, visual, and olfactory inspection.
(b) If an operator operates 500 or more wells within the jurisdiction of a single BLM field office, the operator may only use one or more of the methods identified in paragraph (a)(1), (2), or (3) of this section to detect leaks.
(a) Except as provided below or otherwise authorized in paragraph (b) of this section, the operator must inspect at least semi-annually for leaks the wellhead equipment, facilities, and compressors identified in § 3179.301(b) of this subpart. For purposes of §§ 3179.301 through 3179.305, the term “site” means a discrete area containing wellhead equipment, facilities, and compressors, which is suitable for inspection in a single visit.
(b) The BLM may approve an alternative leak detection device, program, or method under § 3179.302(a)(2) or 3179.302(a)(3) of this subpart, if the BLM finds that the alternative would meet or exceed the effectiveness for leak detection of the approach specified in §§ 3179.302(a)(1) and 3179.303(a) of this subpart. The operator must submit its request for an alternative leak detection device, program, or method of this section through a Sundry Notice.
(c) The operator is not required to inspect or monitor a component that is not an accessible component.
(a) The operator must repair any leak not associated with normal equipment operation as soon as practicable, and in no event later than 15 calendar days after discovery, unless good cause exists for repair requiring a longer period.
(b) If delay in repair beyond 15 calendar days is attributable to good cause, the operator must notify the BLM of the cause by Sundry Notice and must complete repairs within 15 calendar days after the cause of delay ceases to exist.
(c) Not later than 15 calendar days after completion of a repair, the operator must verify the effectiveness of the repair through a follow-up inspection using the same method used to detect the leak.
(d) If the repair is not effective, the operator must complete additional repairs within 15 calendar days, and conduct follow-up inspections and repairs until the leak is repaired.
(e) A follow-up inspection to verify the effectiveness of repairs does not constitute an inspection for purposes of § 3179.303.
The operator must maintain the following records for the period required under § 3162.4-1 of this title and make them available to the BLM upon request:
(a) For each inspection required under § 3179.303 of this subpart, documentation of:
(1) The date of the inspection;
(2) The site where the inspection was conducted; and
(3) The equipment or facility inspected;
(b) The monitoring method(s) used to determine the presence of leaks;
(c) A list of components on which leaks were found and a description of each leak;
(d) The date of first attempt to repair each leak and, if necessary, any additional attempt to repair the leak;
(e) The date each leak was repaired; and
(f) The date and result of the follow-up inspection(s) required under § 3179.304 paragraph (c) or (d) of this subpart.
(a)(1) At the request of a State (for Federal land) or a tribe (for Indian lands), the BLM State Director may grant a variance from any individual provision of this subpart that would apply to all Federal leases, units, or CAs within a State or to all tribal leases, units, or CAs within that tribe's lands, or to specific fields or basins within the State or that tribe's lands, if the BLM finds that the variance would meet the criteria in paragraph (b) of this section.
(2) A State or tribal variance request must:
(i) Identify the provision(s) of this subpart from which the State or tribe is requesting the variance;
(ii) Identify the State or tribal regulation(s) or rule(s) that would be applied in place of the provision(s) of this subpart;
(iii) Explain why the variance is needed; and
(iv) Demonstrate how the State or tribal requirement would satisfy the requirement of the particular provision from which the State or tribe is requesting the variance.
(b) The BLM State Director, after considering all relevant factors, may approve the request for a variance, or approve it with one or more conditions, only if the BLM determines that the State or tribal regulation or rule meets or exceeds the requirements of the provision(s) from which the State or tribe is requesting the variance, and is consistent with the terms of the affected Federal or Indian leases and applicable statutes. The decision to grant or deny the variance will be in writing and is within the BLM's discretion. The decision on a variance request is not subject to administrative appeal under 43 CFR part 4.
(c) A variance from any particular requirement of this rule does not constitute a variance from provisions of other regulations, laws, or orders.
(d) The BLM reserves the right to rescind a variance or modify any condition of approval.
Environmental Protection Agency (EPA).
Final rule.
The Environmental Protection Agency (EPA or the Agency) is issuing amendments to the Non-Hazardous Secondary Materials rule, initially promulgated on March 21, 2011, and amended on February 7, 2013, under the Resource Conservation and Recovery Act. The Non-Hazardous Secondary Materials rule generally established standards and procedures for identifying whether non-hazardous secondary materials are solid wastes when used as fuels or ingredients in combustion units. In the February 2013 amendments, the EPA listed particular non-hazardous secondary materials as “categorical non-waste fuels” provided certain conditions are met. Persons burning these non-hazardous secondary materials do not need to evaluate them under the general case-by-case standards and procedures that would otherwise apply to non-hazardous secondary materials used in combustion units. This action adds three materials to the list of categorical non-waste fuels: Construction and demolition wood processed from construction and demolition debris according to best management practices; paper recycling residuals generated from the recycling of recovered paper, paperboard and corrugated containers and combusted by paper recycling mills whose boilers are designed to burn solid fuel; and creosote treated railroad ties that are processed and then combusted in the following types of units: Units designed to burn both biomass and fuel oil as part of normal operations and not solely as part of start-up or shut-down operations, and units at major source pulp and paper mills or power producers subject to 40 CFR part 63, subpart DDDDD that combust CTRT and had been designed to burn biomass and fuel oil, but are modified (
This rule is effective March 9, 2016.
The EPA has established a docket for this action under Docket ID No. EPA-HQ-RCRA-2013-0110. All documents in the docket are listed on the
George Faison, Office of Resource Conservation and Recovery, Materials Recovery and Waste Management Division, MC 5304P, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (703) 305-7652; email:
The information presented in this preamble is organized as follows:
Categories and entities potentially affected by this action, either directly or indirectly, include, but may not be limited to the following:
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities potentially impacted by this action. This table lists examples of the types of entities of which the EPA is aware that could potentially be affected by this action. Other types of entities not listed could also be affected. To determine whether your facility, company, business, organization, etc., is affected by this action, you should examine the applicability criteria in this rule. If you have any questions regarding the applicability of this action to a particular entity, consult the person listed in the
The Non-Hazardous Secondary Materials (NHSM) regulations at 40 CFR part 241 generally establish standards and procedures for identifying whether NHSMs are solid wastes when used as fuels or ingredients in combustion units. In the February 2013 amendments, the EPA listed particular NHSMs as “categorical non-waste fuels” provided certain conditions are met. Persons burning these NHSMs do not need to evaluate them under the general case-by-case standards and procedures that would otherwise apply to NHSMs used in combustion units. This action adds three materials to the list of categorical non-waste fuels: (1) Construction and demolition (C&D) wood processed from C&D debris according to best management practices, (2) paper recycling residuals generated from the recycling of recovered paper, paperboard and corrugated containers and combusted by paper recycling mills whose boilers are designed to burn solid fuels; and (3) creosote treated railroad ties that are processed and then combusted in the types of units described herein.
The EPA is issuing final amendments to list certain NHSMs as categorical non-waste fuels in 40 CFR 241.4(a) under the authority of sections 2002(a)(1) and 1004(27) of the Resource Conservation and Recovery Act (RCRA), as amended, 42 U.S.C. 6912(a)(1) and 6903(27). Section 129(a)(1)(D) of the Clean Air Act (CAA) directs the EPA to establish standards for Commercial and Industrial Solid Waste Incinerators (CISWI), which burn solid waste. Section 129(g)(6) of the CAA provides that the term “solid waste” is to be established by the EPA under RCRA (42 U.S.C. 7429). Section 2002(a)(1) of RCRA authorizes the Agency to promulgate regulations as are necessary to carry out its functions under the Act. The statutory definition of “solid waste” is stated in RCRA section 1004(27).
Regulations concerning NHSMs used as fuels or ingredients in combustion units are codified in 40 CFR part 241.
• Construction and demolition (C&D) wood processed from C&D
• Paper recycling residuals generated from the recycling of recovered paper, paperboard and corrugated containers and combusted by paper recycling mills whose boilers are designed to burn solid fuel.
• Creosote treated railroad ties that are processed and then combusted in the following types of units: Units designed to burn both biomass and fuel oil as part of normal operations and not solely as part of start-up or shut-down operations, and units at major source pulp and paper mills or power producers
(Refer to section V of this preamble or the regulatory text for a full description of the categorical listings).
Determining whether a material is a solid waste is of particular importance as it relates to CAA section 129. That section states the term “solid waste” shall have the meaning “established by the Administrator pursuant to the Solid Waste Disposal Act.”
RCRA defines “solid waste” as “. . . any garbage, refuse, sludge from a waste treatment plant, water supply treatment plant, or air pollution control facility and
The Agency first solicited comments on how the RCRA definition of solid waste should apply to NHSMs when used as fuels or ingredients in combustion units in an advanced notice of proposed rulemaking (ANPRM), which was published in the
In the March 21, 2011 rule, the EPA finalized standards and procedures to be used to identify whether NHSMs are solid wastes when used as fuels or ingredients in combustion units. “Secondary material” was defined for the purposes of that rulemaking as any material that is not the primary product of a manufacturing or commercial process, and can include post-consumer material, off-specification commercial chemical products or manufacturing chemical intermediates, post-industrial material, and scrap (codified in 40 CFR 241.2). “Non-hazardous secondary material” is a secondary material that, when discarded, would not be identified as a hazardous waste under 40 CFR part 261 (codified in 40 CFR 241.2). Traditional fuels, including historically managed traditional fuels (
A key concept under the March 21, 2011 rule is that NHSMs used as non-waste fuels in combustion units must meet the legitimacy criteria specified in 40 CFR 241.3(d)(1). Application of the legitimacy criteria helps ensure that the fuel product is being legitimately and beneficially used and not simply being discarded through combustion (
Based on these criteria, the March 21, 2011 rule identified the following NHSMs as not being solid wastes:
• The NHSM is used as a fuel and remains under the control of the generator (whether at the site of generation or another site the generator has control over) that meets the legitimacy criteria (40 CFR 241.3(b)(1));
• The NHSM is used as an ingredient in a manufacturing process (whether by the generator or outside the control of the generator) that meets the legitimacy criteria (40 CFR 241.3(b)(3));
• Discarded NHSM has been sufficiently processed to produce a fuel or ingredient that meets the legitimacy criteria (40 CFR 241.3(b)(4)); or
• Through a case-by-case petition process, it has been determined that the NHSM handled outside the control of the generator has not been discarded and is indistinguishable in all relevant aspects from a fuel product, and meets the legitimacy criteria (40 CFR 241.3(c)).
In October 2011, the Agency announced it would be initiating a new rulemaking proceeding to revise certain aspects of the NHSM rule.
•
•
•
•
As discussed in the February 2013 final rule,
To supplement the comments identified in the February 2013 rule, the Agency received additional information on these two NHSMs from stakeholders (see section V of this preamble). As discussed in the following sections, the EPA has determined the information received to date, when taken together, supports a categorical determination of these materials as non-waste fuels and is today listing them as categorical non-waste fuels in 40 CFR 241.4(a).
In addition to paper recycling residuals and construction and demolition debris, the Agency identified creosote-treated railroad ties in the February 2013 final rule as a potential candidate for a categorical non-waste listing based on comments from stakeholders. However, the Agency indicated that additional information would need to be submitted before this NHSM could be addressed. If such information supported the representations made by industry—that is, the American Forest & Paper Association (AF&PA) and the American Wood Council—EPA stated that it expected to propose a categorical listing for this material as well. Finally, we noted in the February 2013 final rule that the Agency received a letter from the Treated Wood Council asking that non-hazardous treated wood be categorically listed—a broad category that would include creosote-treated railroad ties. The Agency noted it was in the process of reviewing the information in the letter and would consider whether to propose a categorical listing for this broader set of treated wood material.
The Agency has reviewed the information submitted from stakeholders regarding creosote-treated railroad ties. As discussed in the following sections, the EPA has determined that the information received to date, when taken together, supports a categorical determination for creosote-treated railroad ties when combusted in the types of units described herein and is listing them as categorical non-wastes fuels in 40 CFR 241.4(a).
The February 7, 2013 revisions to the NHSM rule discuss the process and decision criteria whereby the Agency would make additional categorical non-waste determinations. (See 78 FR 9158.) While the categorical non-waste determinations in this action are not based on rulemaking petitions, the criteria the EPA used to assess these NHSMs as categorical non-wastes match the criteria to be used by the Administrator to determine whether to grant or deny the categorical non-waste petitions.
Based on the information in the rulemaking record, including stakeholder comments, the Agency is amending 40 CFR 241.4(a) by listing three additional NHSMs as categorical non-wastes. Specific determinations regarding C&D wood, paper recycling residuals, and creosote-treated railroad ties as categorical non-wastes and how the information was assessed by EPA according to the criteria in 40 CFR 241.4(b)(5) are discussed in detail in section V of this preamble.
In this section, the EPA provides the rationale for its determination that the three additional NHSMs are appropriate for listing as categorical non-wastes, under certain conditions. It also addresses major comments the Agency received regarding the three NHSMs proposed in the April 14, 2014 rule (79 FR 21005).
The April 14, 2014 proposed rule described C&D wood in detail (79 FR 21010-11), explained the status of C&D wood under current rules, discussed comments received during previous proceedings, as well as the scope of the proposed non-waste listing (79 FR 21011-12). The proposed rationale for the listing is found in the proposal at 79 FR 21012-16 and is summarized and incorporated into this final rule, along with all sources referenced in that discussion and cited therein. The final decision in this rule is based on the information in the proposal and supporting materials in the rulemaking record. Any changes made to the final rule are based on the rationale, as described below.
As described in the proposed rule (79 FR 21010-11) and reiterated here, C&D wood is generated from the processing of debris from construction and demolition activities for the purposes of recovering wood. At
Also, because clean C&D wood is considered “clean cellulosic biomass” and is already excluded from being a solid waste,
With respect to how C&D debris is handled, we noted in the proposal and find in this final rule that, although contractors may segregate C&D debris at building sites, the common practice—at demolition sites in particular—is to send co-mingled debris to independent C&D recycling or processing facilities. At these facilities, operators recover wood scraps from a mixture of building materials that often includes metals, concrete, plastics, and other items that are unsuitable for energy recovery in combustion units. Some operators use “positive sorting” techniques, meaning
C&D wood processing facilities can use a variety of techniques to remove or exclude debris unsuitable for a product fuel. Typically, processors use some combination of source control, inspection, sorting, and screening to meet the specifications identified by their customers (
In both the March 21, 2011 and February 7, 2013 NHSM final rules, EPA discussed two scenarios under which the Agency would consider C&D wood to be a non-waste fuel.
Although the December 2011 NHSM proposed rule did not discuss or solicit comments on processed C&D wood, a number of commenters submitted comments arguing processed C&D wood (
• It is utilized in combination with other biomass materials to optimize and manage combustion in boilers due to its low moisture/high heat characteristics.
• It is sufficiently processed to remove impurities.
• From a practical materials management standpoint, C&D materials are not discarded; collection of most of these materials is planned for, with C&D recycle sorting and processing yards receiving the materials as a destination and the point of generation of the fuel product.
• Commenters detail the processing and test data available for C&D materials, which demonstrates their value as a fuel.
• Commenters noted the EPA has already included clean C&D materials in their proposed clean cellulosic biomass definition for traditional fuels, but EPA elsewhere identifies C&D materials that are not clean as subject to the legitimacy criteria.
The commenters argued, therefore, the EPA should remove doubt and list these materials in the newly proposed 40 CFR 241.4(a) as a non-waste fuel given both their demonstrated fuel value and the industry that has been established for recycling these NHSMs into useful product fuel.
Expanding further on these comments, several trade organizations submitted information in support of a categorical non-waste determination that would list processed C&D wood as a product fuel when burned in combustion units. The information suggested that a non-waste listing include all C&D wood processed in accordance with industry practices proven to produce a wood product meeting the NHSM legitimacy criteria. The commenters identified “proven practices” as the sorting (both mechanical and manual) of C&D material to separate the following contaminants: Non-wood material, wood treated with pentachlorophenol, chromated copper arsenic (CCA) treated wood, or other copper, chromium or arsenical preservatives, and lead (through the separation of either lead-painted wood or fines or through other means as specified in applicable state law). Commenters also compiled a dataset of contaminant concentrations in processed C&D wood from nine combustion facilities in seven states to demonstrate the efficacy of the identified practices.
Case-by-case analysis is not necessary, the trade organizations contended, to ensure sufficient processing occurs and that C&D wood products—produced by different processors using different sorting techniques—are consistently managed as a valuable commodity, have meaningful heating values, and contain contaminants at levels comparable to or lower than traditional fuels. Instead, they argued persons burning C&D wood for energy recovery only need to certify the processed C&D wood came from a facility using the aforementioned sorting practices.
Other commenters on the December 2011 NHSM proposed rule asserted that
Based on information in the record, including comments submitted before proposal, the Agency proposed the categorical non-waste listing for wood recovered from C&D debris which has been processed according to best management practices to remove certain contaminants, as a categorical non-waste in 40 CFR 241.4(a). Under the proposed rule, combustors of C&D wood must obtain a written certification from C&D processing facilities that the C&D wood has been processed by trained operators in accordance with best management practices.
C&D processing facilities that use negative sorting (where operators remove contaminated or otherwise undesirable materials from co-mingled debris) must remove fines,
This rule finalizes the criteria and requirements discussed in the proposal for reasons explained in the proposal, with three changes to the regulatory language for lead elimination requirements for both positive and negative sorting facilities, two changes to the definition of C&D wood, and the addition of new language for the processor's written certification and training requirements. The changes and additions were made in response to comments received and based on other supporting information in the record and to provide clarity to the best management practice requirements, as well as the definition of C&D wood. The rationale for the changes and additions that have been made in the final rule are explained below in this section. The general rationale for the final listing is provided in the next section V.A.4. of this preamble.
The proposed regulatory language resulted from a presumed scenario in which C&D debris was sent to a single, centralized processing facility. However, there are other processors who receive segregated or pre-sorted C&D wood from small generators.
Recall that negative sorters are required to remove fines to ensure lead concentrations in the product fuel are comparable to or lower than wood or biomass. Positive sorters, however, are not required to remove fines because only the desirable wood is picked from the C&D debris. Thus, to require a “chip and grind” processing operation that has received positive sorted C&D wood to remove fines when there are none present is unnecessary. Therefore, the language for positive sorting has been revised to include processors that receive pre-sorted wood from positive sorting entities. This revision clarifies that these processors are not negative sorters for purposes of identifying which lead requirements are applicable. Specifically, the final language at 40 CFR 241.4(a)(5)(i) includes new text (see italic print) to capture these facilities: “C&D processing facilities that use positive sorting—where operators pick out desirable wood from co-mingled debris—
Another change was made to the lead elimination requirements, but for negative sorters. The term “all” was added to the options for removing painted wood under 40 CFR 241.4(a)(5)(ii)(A). This requirement is now consistent with the corresponding requirement for positive sorting facilities and emphasizes that if processors choose this particular lead elimination option, then any painted
The third change that has been made applies to both positive and negative sorters. As stated in the previous paragraph, the term “all” has been added to the negative sorting requirements for consistency and to reaffirm that this particular option is intended to be a stringent standard. However, to provide additional clarity regarding the Agency's position on
In the proposed rule, the Agency noted clean wood in disaster debris had been included in the definition for “clean cellulosic biomass” in a prior rulemaking, but had not addressed clean wood from disaster debris mixed with contaminated materials (
The Agency finds that these concerns regarding the management of large volumes of material in an expeditious nature would only be relevant if the best management practices as finalized in this rule are not used to process wood from natural disaster debris. The Agency finds that the best management practices set forth in this rule are sufficient to ensure natural disaster debris is handled and processed in the same manner as other C&D debris, regardless of the source or quantity of material to be processed. In other words, processors that comply with the best management practices for this listing would not be altering the way in which they process the debris. Should a processor choose to hire and train additional sorters or extend operational hours to process higher volumes, the limiting factors in this rule that will continue to ensure the quality of the processed material are the best management practices and the training and certification requirements. Furthermore, the information provided to the Agency discusses that when the incoming material exceeds processing capacity, the excess material is stored or sent to a landfill.
The second revision made to the definition of C&D wood is to broaden the description of C&D wood generated from construction activities. As proposed, commenters interpreted it to be limited in scope because it did not capture the many sources of wood generated from construction activities, particularly for installation activities. The wording in the second sentence of the proposed definition for C&D wood at 40 CFR 241.2 read: “C&D wood from construction activities results from
The second regulatory addition is to specify the written certification requirements. As discussed in the proposal, to ensure the C&D wood is processed according to best management practices, it is important for the processor to certify they are meeting such best management practices using trained operators (79 FR 21013). The Agency has determined a written certification from the processor is a necessary mechanism for ensuring best management practices have been used and for indicating that the processor has used trained operators. The Agency recognizes contracts and purchase agreements can indicate a commitment to quality, but also specifications can vary according to the needs of one combustor versus another. More importantly, the contracts and purchase agreements that the Agency has seen do not show that C&D wood has been processed according to any particular best management practices, and consequently, cannot ensure that the resulting material is not a waste when combusted. Therefore, the written certification is finalized at 40 CFR 241.4(a)(5)(iv) and states “[a] written certification must be obtained by the combustor for every new or modified contract, purchase agreement, or other legally binding document, from each final processor of C&D wood and must include the statement: the processed C&D wood has been sorted by trained operators in accordance with best management practices.” This certification will assist the combustor's determination that the C&D wood has been sufficiently processed to meet the conditions of this categorical non-waste listing. Refer to the section V.A.5 of this preamble for additional background.
This section discusses the reasoning provided in the proposed rule and the reasons for the EPA's final determinations for the categorical listing of C&D wood. EPA adopts the reasoning in the proposed rule and further explains it in this preamble. Further explanations for the Agency's decision are provided in the Response to Comments below. The proposal, this section, and the Response to Comments all constitute the Agency's final determination supporting this rule.
When deciding whether an NHSM should be listed as a categorical non-waste fuel in accordance with 40 CFR 241.4(b)(5), the Agency first evaluates whether or not the NHSM has been discarded in the first instance and, if not so discarded, whether or not the material could be considered discarded because it is not legitimately used as a product fuel in a combustion unit. Based on the rulemaking record, as discussed below, the Agency has determined C&D wood is not discarded when: It is processed in accordance with best management practices described herein; it is legitimately used as a product fuel in a combustion unit; and when combustors of C&D wood have obtained a written certification from C&D processing facilities that the C&D wood has been processed by trained operators.
In the April 14, 2014 proposed rule (79 FR 21012), the Agency reiterated the determination in the existing rules that the wood present in C&D debris is considered to be a solid waste prior to processing and that persons must transform the debris into a legitimate product fuel in order to burn the material as a non-waste fuel.
Compared to mixed C&D debris, processed C&D wood will have significantly fewer contaminants and improved fuel characteristics. Specifically, the removal or exclusion of specified materials, such as creosote-treated wood (PAHs, dibenzofuran), pentachlorophenol-treated wood (pentachlorophenol, dioxins), CCA-treated wood (chromium, arsenic), other copper, chromium, and arsenical treated wood, plastics (chlorine), drywall (sulfur), lead-based paint (lead), as well as insulation and other materials containing asbestos,
For incoming C&D debris, processing facilities can use a variety of techniques to exclude or remove debris unsuitable for a product fuel. Typically, processors use some combination of source control, inspection, sorting, screening, and grinding to meet the specifications identified by their customers (
Further, to ensure the C&D wood is processed according to best management practices, the Agency had proposed to require processors to certify they are meeting such best management practices using trained operators. This requirement has been finalized in this rule for the reasons discussed earlier in section V.A.3. of this preamble. Combustors must obtain a written certification for every new or modified contract, purchase agreement, or other legally binding document, from each
The Agency has determined that, when C&D wood is processed according to the best management practices, it will have significantly fewer contaminants and improved fuel characteristics. The best management practices ensure the contaminants in the fuel that is burned will not be unpredictable, regardless of the type or number of processing techniques used. Thus, this rule finalizes the best management practices, with some minor changes from the proposed regulatory language as discussed previously in section V.A.3. of this preamble.
In determining whether to list processed C&D wood as a categorical non-waste fuel in 40 CFR 241.4(a), the Agency evaluated the legitimacy criteria in 40 CFR 241.3(d)(1)—that is, whether it is managed as a valuable commodity, whether it has a meaningful heating value and is used as a fuel in a combustion unit to recover energy, and whether contaminants or groups of contaminants are at levels comparable to or less than those in the traditional fuel the unit is designed to burn. To the extent that processed C&D wood does not meet one or more of the legitimacy criteria, the Agency has considered other relevant factors in determining to list C&D wood as a categorical non-waste fuel in 40 CFR 241.4(b)(5)(ii) (see discussion on formaldehyde below).
Regarding the first legitimacy criterion, the information in the record in support of the proposal and this final rule demonstrates that both processors and combustors manage processed C&D wood as a valuable commodity. Specifically, after processing, including grinding to size, processors ship the material to energy recovery facilities in covered chip vans or semi-trailers. The material is then stored on-site at the combustion facilities in wood fuel storage yards and generally used within 90 days of delivery.
With respect to the second legitimacy criterion, the record shows that processed C&D wood has a meaningful heating value and is used as a fuel to recover energy. Specifically, information in the rulemaking record demonstrates that processed C&D wood has an average as-fired energy content of 6,640 Btu/lb,
For the third legitimacy criterion, C&D trade organizations provided the Agency with contaminant analyses of more than 220 samples of processed C&D wood from nine combustion facilities in California, Maine, Massachusetts, Minnesota, New York, the state of Washington, and Wisconsin in support of the proposed categorical listing for processed C&D wood. The Agency compared the contaminant levels found in the processed C&D wood to the contaminant levels found in clean wood and biomass materials since any unit burning processed C&D wood can clearly burn clean wood and biomass materials as well.
As first presented in the April 14, 2014 proposed rule (79 FR 21013-14), summary results for the contaminant comparisons are provided in Table 1 of this preamble, with the contaminants most likely to be present in unprocessed C&D debris listed first. The Agency finds that they support the final determination that processed C&D wood meets the contaminant legitimacy criterion, with the appropriate qualifications as noted below.
Specifically, arsenic and chromium are present due to CCA-treated wood; lead due to lead-based paint chips; mercury due to light bulbs, ballasts, thermostats and other mercury-containing devices present in buildings; chlorine due to PVC and other plastics; sulfur due to plaster or drywall containing gypsum, a sulfate mineral; formaldehyde due to resinated wood; and pentachlorophenol due to utility poles and other treated wood products currently accepted by some combustion facilities. Although sources of fluorine in C&D debris are less clear, the contaminant's presence may be due to its use in flame retardants incorporated into carpet, furniture, and other building materials.
With the exception of four contaminants—fluorine, lead, formaldehyde and pentachlorophenol, every sample of processed C&D wood's contaminant levels was well within the range of clean wood and biomass materials. With respect to these four contaminants:
• Fluorine: This contaminant was first discussed in the proposal at 79 FR 21014. While only one sample out of 45 samples of processed C&D wood exceed the range for fluorine in clean wood and biomass, the Agency still considers fluorine to be at levels comparable to those found in clean wood and biomass since this lone sample is present within a small acceptable range (
• Lead: As first discussed in the proposal at 79 FR 21014-15, April 14, 2014, despite efforts by C&D processing facilities to remove lead, the data demonstrate that some processing facilities do a better job than others, with isolated samples from Massachusetts reaching 407 and 437 ppm lead, and one of seven samples from Wisconsin reaching 482 ppm lead. While most of the 224 samples detected lead within the range found in clean wood and biomass materials (ND-340 ppm), it is important to recognize that each high sample could represent a large amount of processed C&D wood produced by an outlier facility. Accordingly, an overly broad categorical non-waste listing could include processed C&D wood from facilities where the final product consistently contains high lead levels, amounts that would not be considered a normal part of clean wood or biomass. In this instance, one facility in Massachusetts provided a composite sample for each of seven days, and two out the seven samples exceeded the range of lead values found in clean wood and biomass. That could mean more than 28 percent of the processed C&D wood produced by that facility exceeds lead levels found in clean wood and biomass.
C&D processing facilities have options for eliminating lead in the processed C&D wood they produce, and information submitted with the contaminant dataset shows that the two facilities (one in Massachusetts, the other in Wisconsin) exhibiting the highest lead levels shared similar lead elimination strategies. Although both facilities accept painted wood, neither uses X-ray Fluorescence (XRF) analyzers to detect and remove lead-based painted wood. Nor do they require documentation of a building inspection that includes testing for lead-based paint. By comparison, the Washington facility included in the dataset requires documentation of XRF testing before accepting demolition debris from a particular building, and as evidenced by a maximum lead concentration of 26 ppm, lead concentrations in the processed C&D wood it burns tested lower than for any other facility in the dataset. The Minnesota facility included in the dataset does not accept painted wood, and as evidenced by a maximum lead concentration of 110 ppm, lead concentrations in the processed C&D wood it burns are also well within the range of clean wood and biomass materials.
Both the Massachusetts facility and the Wisconsin facility relied solely on removing “fines” to control lead levels. Fines are small-sized particles that may contain relatively high concentrations of contaminants, and facilities can remove them before and after shredding via screens or flotation. The Agency does not dispute that the removal of fine particles can reduce the levels of lead and other contaminants, particularly for C&D processing facilities using negative sorting. Without additional measures, however, this strategy does not remove sufficient lead to transform the C&D
No additional data were received in response to the proposed measures to eliminate lead that warrant removal of the conditions or their options for the final listing. However, as discussed earlier in section V.A.3. of this preamble, three changes have been made to the proposed regulatory language: (1) Positive sorting has been revised to include processors that receive pre-sorted wood from positive sorting entities to clarify that these processors are not negative sorters for purposes of identifying which lead elimination requirements are applicable; (2) the word “all” has been added to clarify that both positive and negative sorters must exclude or remove all painted wood from incoming debris; and (3) the parenthetical language: “to the extent that only
Based on all information regarding the presence of lead in processed C&D wood, the Agency has determined that the proposed conditions are necessary to ensure that lead levels in processed C&D wood are comparable to or lower than lead levels present in clean wood and biomass. Consistent with the proposal, the Agency has finalized conditions designed to eliminate lead, with the minor changes as noted above. See the final regulatory language at 40 CFR 241.4(a)(5)(i) and (ii).
• Pentachlorophenol: The following was first discussed in the proposal at 79 FR 21015. The presence of pentachlorophenol in some processed C&D wood results from processors either choosing to include industrial wood products treated with pentachlorophenol in their product fuel (in the case of positive sorting) or from processors not removing those same industrial wood products from C&D debris (in the case of negative sorting) prior to the final grinding step. The EPA restricted the use and sale of pentachlorophenol in 1987, with no registered residential uses allowed for the past 26 years. As stated in the proposal, the Agency believed that the pentachlorophenol concentrations in processed C&D wood were a direct result of easily identified wood products, predominantly utility poles, that processing facilities can choose to exclude or remove prior to grinding recovered C&D wood.
Information submitted in response to the proposed rule affirm that the pentachlorophenol concentrations in processed C&D wood are a direct result of easily identified wood products, predominantly utility poles, that processing facilities can choose to exclude or remove prior to grinding recovered C&D wood.
• Formaldehyde: The proposal first discussed this contaminant at 79 FR 21015, April 14, 2014. For C&D debris processed pursuant to best management practices, inclusive of the regulatory conditions presented in the proposal, formaldehyde (present in concentrations as high as 176.8 ppm versus 27 ppm in clean wood/biomass) is the only remaining contaminant that raised questions as to whether it meets the contaminant legitimacy criterion. Again, the Agency emphasizes that, although the situation appears similar to the categorical non-waste listing for resinated wood in 40 CFR 241.4(a)(2), details surrounding use of the two NHSMs as fuel are not the same. In the case of resinated wood, as defined in 40 CFR 241.2, the Agency determined that energy recovered from the combustion of manufacturing process residues and off-specification resinated wood is integrally tied to the industrial production process. The equivalent for C&D wood would be sawmills reliant on recovering energy from sawdust and off-specification lumber to power the construction lumber production process. Sawmills may do this, but that is not the scenario commenters have described in response to the December 23, 2011 (76 FR 80451) proposed rule and for which the Agency has evaluated.
While EPA disagreed with petitioners' claims that resinated wood components in C&D debris are categorical non-wastes and the corollary that formaldehyde concentrations are therefore irrelevant, the Agency agreed in the proposal that additional factors were worth considering in determining whether to list processed C&D wood categorically as a non-waste fuel. First, formaldehyde concentrations in processed C&D wood may reach 176.8 ppm, but are lower than in pure resinated wood, which may reach 200 ppm. National rules developed by the CARB Composite Wood ATCM, per Public Law 111-199, will ensure that newly produced resinated wood will contain even less formaldehyde in the future by setting limits on how much formaldehyde may be released.
The Agency has determined that the additional factors discussed in the proposal are appropriate for determining whether the resinated wood in certain limited circumstances is actually a product fuel. As a result, in the final rule the Agency allows resinated wood to remain in C&D wood prior to processing for this categorical non-waste listing. This determination is based partially on the fact that future rules will limit levels of formaldehyde in wood products and will, in effect, also reduce the levels of formaldehyde in processed C&D wood. Principally, the Agency's determination is based on information submitted to the Agency showing that some processors choose to include resinated wood in processed C&D wood based on combustor specifications for a higher Btu value fuel, which demonstrates that resinated wood is a valuable product fuel and is not burned for destruction. The Agency maintains that the benefits of burning kiln-dried wood not only provides higher heating value, but also more consistent moisture content which lends to more efficient combustion and, thus, reduced emissions of certain contaminants. The final rule, therefore, allows processors to choose whether they will exclude or remove any resinated wood and still be permitted to be within the categorical non-waste listing for C&D debris.
This does not mean, however, that all resinated wood is considered a non-waste fuel. The Agency has found that resinated wood is a non-waste fuel in the furniture industry because of particular circumstances in that industry, and in this case for C&D wood due to the extraction of fuel value as a result of the kiln-dried properties of that wood. In other circumstances, a case-by-case determination would need to be made.
The proposed rule identified several issues pertaining to the listing of C&D wood as categorical non-wastes and requested comment on those issues as follows.
One pilot study conducted in the state of Florida showed that visual sorting of CCA-treated wood at three different facilities produced differing results of success. The two facilities with the greatest success, which correctly identified 89 percent and 90 percent of the pre-sorted wood as untreated wood, had provided extensive training to its employees. The third facility correctly identified 60 percent as untreated wood, as evidenced by little or no training.
Given the variability in visually identifying untreated versus treated wood, augmenting technologies have been developed to detect the presence of arsenic, copper, and chromium, as well as other contaminants. Studies have concluded that the use of stains (
Again, the Agency's concern was based on anticipated increases of CCA-treated wood in C&D debris, as well as the accuracy of visual sorting among C&D processors. Therefore, the Agency had requested comment on the viability of either requiring, as best management practices, C&D processors to implement formal training programs that emphasize sorting treated wood from untreated wood or the use of XRF technology or PAN indicator stains to provide greater certainty that CCA-treated wood is removed from the processed C&D wood.
After considering the information in the record, including comments received, the Agency has determined that CCA-treated wood must be excluded or removed from C&D debris, by trained operators, to ensure that levels of arsenic and chromium in processed C&D wood remain comparable to or lower than levels in clean wood and biomass. Unlike formaldehyde levels which are expected to decrease over time, levels of arsenic and chromium are expected to increase with continued use of CCA-treated lumber or other copper, chromium, or arsenical preservatives.
The Agency's decision to require that operators be trained to exclude or remove treated wood (with the exception of resinated wood) as part of the best management practices, is based in part on the results from the Florida pilot study which showed a high rate of success when extensive training was provided for visual identification of treated wood; and in part because both XRF technology and PAN indicator
The Agency finds that the concerns as expressed in the proposal would only be relevant if the best management practices, as finalized in this rule, are not followed. As discussed previously in the section on processing (See section V.A.4.a.i. of this preamble), the best management practices ensure that the contaminants in the fuel that is burned will not be unpredictable regardless of the source of the wood, or even the quantity of wood to be processed. In other words, processors that comply with the best management practices for this listing would not be altering the way in which they process the debris. Should a processor choose to hire and train additional sorters or extend operational hours to process higher volumes, the limiting factors that will continue to ensure the quality of the processed material are the best management practices and training and certification requirements. (For additional discussion on handling practices, refer to section V.A.3. of this preamble.) Thus, clean wood from natural disaster debris that is mixed with other materials and is delivered to a processing facility has been added to the definition of C&D wood. However, the disaster debris must be processed in the same manner as C&D wood recovered from demolition activities to qualify for the categorical non-waste listing.
In the proposal, the Agency did not prescribe what a training program could include due to several factors that contribute to variability within the C&D processing industry. Certain factors such as where the C&D debris originates from and the amount of sorting prior to arrival at the processing facility can influence the extent and type of contaminated material arriving at the processing facility. Also, whether positive or negative sorting is used and the scale of the processing facility (
For this final listing, the Agency is not prescribing the elements of a training program and maintains that flexibility is necessary to address the variability within the industry. However, the Agency is finalizing a requirement for processors to train their operators in accordance with the best management practices. The Agency did not include a specific training requirement for processors because it had intended to rely on a written certification as a means for processors to show that they had used “trained” operators. After further consideration, the Agency finds that this approach does not provide any assurance that the processor is conducting the necessary training in order to ensure that the resultant material is not discarded when combusted and is, therefore, not a waste. Although the written certification, as proposed and finalized in this rule, is intended to confirm that the processed C&D wood has been sorted by “trained” operators in accordance with best management practices, it does not require any evidence that training has taken place, nor does it hold the processor accountable. Thus, a mechanism is necessary to document when the training has been conducted so that processors are accountable to their customers when certifying that they have used trained operators. This mechanism is implemented via new regulatory language at 40 CFR 241.4(a)(5)(iii) which states that “[p]rocessors must train operators to exclude or remove the materials as listed in paragraph (a)(5) of this section from the final product fuel. Records of training must include dates of training held and must be maintained for a period of three years.” The training requirement serves as an additional condition of this categorical non-waste listing. This condition is applicable only to the final processor, because it is ensuring that processing has transformed the processed C&D wood into a non-waste product fuel according to best management practices before providing it to the combustor, and the final processor is responsible for meeting individual combustor specifications. However, it is important to note that the C&D materials at the intermediate processor facilities would still be solid wastes.
The Agency has determined that a written certification statement developed specifically to address requirements of the categorical non-waste listing will provide independent assurance that processors are providing a legitimate product fuel to their customers. Although contracts and purchase agreements indicate a commitment to quality, specifications can vary according to the needs of one combustor versus another with respect to the extent and type of contaminant removal required. The contracts and purchase agreements that the EPA has seen do not show that C&D wood has been processed according to any particular best management practices, and consequently, cannot ensure that the resulting material is not a waste when combusted. The written certification statement is required only for the final processor, since it is responsible for ensuring that the final product fuel has been processed according to best management practices. Note that the materials at intermediate processor facilities would still be solid wastes. Therefore, this final rule requires combustors to obtain a written certification from the final processor for every new or modified contract, purchase agreement, or other legally binding document. This written certification statement must state that the processed C&D wood has been sorted by trained operators in accordance with best management practices. See the new requirements at 40 CFR 241.4(a)(5)(iv).
Clean wood in disaster debris had been included in the definition for “clean cellulosic biomass” in a prior rulemaking. When clean wood is picked/sorted (
The proposal expressed concern regarding the management of disaster debris prior to processing, such that due to the circumstances, large quantities of debris would need to be managed expeditiously, and consequently may contain more contaminated materials that would have been typically sorted out prior to arrival at a processing facility. However, after considering the comments and evidence in the record, the Agency finds that these concerns regarding the management of large volumes of material in an expeditious nature, would only be relevant if the best management practices as finalized in this rule, are not used to process wood from natural disaster debris. The best management practices set forth in this rule are sufficient to ensure that natural disaster debris is handled and processed in the same manner as other C&D debris, regardless of the source or quantity of material to be processed. In other words, processors that comply with the best management practices for this listing would not be altering the way in which they process the debris. Should a processor choose to hire and train additional sorters or extend operational hours to process higher volumes, the limiting factors in this rule that will continue to ensure the quality of the processed material are the best management practices and training and certification requirements. Further, the information provided to the Agency shows that when the incoming material exceeds processing capacity, the excess material is stored or sent to a landfill. Given the best management practices and information indicating the typical handling of excess material, the Agency has determined that it is appropriate to include disaster debris in the definition of C&D wood. Thus, clean wood from natural disaster debris that is mixed with other materials and is delivered to a processing facility has been added to the definition of C&D wood. However,
The Agency disagrees with the suggestion to develop specific contaminant levels. We previously said that if we were to consider such an approach, the Agency would have to establish a line for what is acceptable and the line may either be somewhat arbitrary or it may exclude materials that, if carefully considered, should be considered legitimate. On the other hand, case-by-case comparisons by each person evaluating this legitimacy criterion can take into account the wide variety of NHSMs, as well as the appropriate traditional fuel to which it is being compared. Because this factor must apply to various different recycling activities and industries, the case-by-case approach is most appropriate.
In the case of a categorical non-waste listing, the Agency may list a specific NHSM when it has determined that the NHSM has not been previously discarded, or if discarded, has been sufficiently processed, and is legitimately used as a product fuel. When an NHSM is listed as a categorical non-waste, persons that generate or burn processed C&D wood will not need to make individual (
Contrary to scrap tires, mixed C&D debris (
The Agency has discussed its position on processing of discarded secondary materials at length in the March 21, 2011 final rule. For discarded secondary materials, when sufficient processing has been performed and if the resulting material meets the legitimacy criteria, the fuel or ingredient product would be considered a non-waste material (76 FR 15475-76, March 21, 2011). The Agency has determined previously that C&D debris can be processed to transform the C&D wood into a product fuel that meets the legitimacy criteria (76 FR 15485, March 21, 2011 and 78 FR 9138, February 7, 2013). Further, the Agency has determined that processed C&D wood is appropriately listed as a
The Agency is concerned however, that lead painted wood and fines containing lead can contribute to elevated levels of lead in processed C&D wood. Thus, the Agency proposed and has finalized in this rule certain best management practices designed to eliminate sources of lead in processed C&D wood. C&D processors have options for excluding (positive sorting) or removing (negative sorting) sources of lead: Excluding or removing all painted wood from the incoming material, using X-ray Fluorescence to detect and exclude or remove lead-painted wood from the product fuel, or requiring documentation that a building has been tested for and does not include lead-based paint before accepting the demolition debris. In addition, negative sorting facilities must also remove fines during processing.
The Agency also agrees that other types of treated wood are often present in C&D debris. To address potentially elevated levels of other contaminants in treated wood, the Agency had proposed and has finalized in this rule best management practices to designed to eliminate specific types of treated wood from processed C&D wood. The best management practices require exclusion or removal of wood treated with creosote, pentachlorophenol, chromated copper arsenate, or other copper, chromium, or arsenical preservatives. In addition, the best management practices require exclusion or removal of non-wood materials such as plastics, drywall, concrete, aggregates, dirt and asbestos. See 40 CFR 241.4(a)(5). For a detailed discussion of the final best management practices, please refer to section V.A.3. of this preamble.
The best management practices ensure that the contaminants in the fuel that is burned will be predictable, regardless of the type or number of processing techniques used or the source of the C&D debris. Thus, the Agency does not agree that it is necessary to require contaminant testing for this categorical non-waste listing. However, if a person chooses not to take advantage of this categorical non-waste listing, then a case-by-case determination would need to be made that the C&D wood has been sufficiently processed according to 40 CFR 241.2 and meets the legitimacy criteria according to 40 CFR 241.3(d)(1).
Another comment suggested that the words “to the extent practical” be added to the current language for clarification that 100 percent exclusion or removal is not required. The EPA should revise the description of best management practices to remove the implication that 100 percent of the listed materials are to be removed or excluded.
The concept of
To include language as the comments suggested, such as to “substantially exclude or substantially remove” or “to the extent practical,” gives the perception that the best management practice standard is not a stringent requirement, but akin to a “best efforts” standard. This would not be an acceptable standard to ensure that processed C&D wood is a legitimate product fuel. Thus, the Agency has determined that it is not necessary or accurate to modify or add terms to the regulatory language to state that 100 percent exclusion or removal is not required.
First, 100 percent removal of unwanted material is not technically feasible, practicable, nor necessary to produce a legitimate fuel product.
Second, one option for removal of lead painted wood is the use of XRF “to ensure that painted wood included in the final product fuel does not contain lead-based paint.” The EPA cites the University of Florida pilot study of a conveyor system that was funded by the manufacturer of XFR equipment. This is a pilot study that has not been demonstrated for an industrial setting. In fact, it has a throughput of only 20 tons per hour while most C&D processing facilities are permitted to manage 500 tons a day or more and operate on only one shift a day. It is neither feasible nor practicable to “ensure” all wood painted with lead-based paint is removed using XRF technology. The C&D processors that currently use XRF use a hand held gun to test a sample of an incoming load. None use the conveyor system described in the University of Florida study.
The lead paint testing option raises similar concerns. It is assumed that the EPA is not suggesting that every square foot of painted wood be tested.
It is requested that the EPA modify the description of these management practices to remove the implication that 100 percent removal is technically feasible and practicable and allow C&D processors to screen samples, not every piece of painted wood. To clarify these issues, the EPA could modify the regulatory language for both positive and negative sorting such that the second option would read, “use X-ray Fluorescence to test a sample of painted wood from each source or supplier of demolition debris received by the C&D wood processor to identify and reject wood with lead-based paint.” For the third option, it would read “require documentation that a sample of painted wood from a building has been tested for and does not include . . .”
Moreover, it is important to understand that the limits imposed in a Clean Air Act permit have no bearing on what is determined to be a waste or non-waste under RCRA when the material goes to a combustion facility. The point is that Clean Air Act permits must apply to the input material—whether they are wastes or not, and control of the associated emissions. The input material determines which Clean Air Act standards (
Second, the Agency does not agree with the suggested language that would specify testing for a representative sample or “sample of painted wood from each source or supplier” be performed for purposes of meeting the XRF lead elimination option. The term “sample” can vary in interpretation from one processor to another, with some analyzing more samples than others which could result in significant amounts of lead. This would indicate disposal rather than use as a product fuel. The proposed language at 40 CFR 241.4(a)(5)(i)(B) and (ii)(B) which states, “[u]se X-ray Fluorescence to ensure that painted wood included in the final product does not contain lead-based paint . . .” is intended to be a stringent standard, which the Agency adopts for the final rule. The expectation is that if a processor accepts painted wood, then it must determine if the paint is lead-based. If it is positive for lead, then that piece of wood must be excluded or removed. The same applies to the language at 40 CFR 241.4(a)(5)(i)(C) and (ii)(C) that requires documentation that a building has been tested for and does not include lead-based paint prior to accepting demolition debris from that building. The Agency is not including regulatory language in regard to sampling. Rather, the frequency of sampling should be determined by the processor such that the processor can ensure that the accepted painted wood is not lead-based.
The Agency is convinced by the data that when XRF technology is used, the lead levels in processed C&D wood are comparable to or below the lead levels found in clean wood and biomass. Specifically, a facility located in Washington State receives co-mingled C&D debris. Prior to materials being accepted for processing, a rigorous inspection process is carried out, including documentation showing that the building was inspected for asbestos containing materials if it was from a demolition or renovation project, and visual inspections and lead-based paint testing through XRF. As a result, the ten samples analyzed show an average lead concentration of 10.6 ppm, with a maximum of 26 ppm.
If a processor chooses to accept and include painted wood for processing, then the painted wood either must be analyzed via XRF or documentation must be provided from a demolition or renovation project indicating that painted wood has been analyzed and does not contain lead. As noted above, the frequency of sampling should be determined by the processor such that the processor can ensure that the accepted painted wood is not lead-based. The Agency finds that the lead elimination options for both XRF and documentation that a building has been tested for and does not include lead-based paint prior to accepting demolition debris from that building, are appropriate and finalized as proposed.
To respond to the comment about the Agency's citation of the XRF conveyor system in the University of Florida pilot-study, we understand that processors would be hesitant to make a significant investment in a XRF conveyor system that has not yet been proven in a large industrial setting. The aspect of the study that the Agency found relevant was the discussion of the benefit of providing extensive training to operators for visual recognition of treated wood. The Agency does not promote one XRF technology over another. The Agency recognizes that not all processors use XRF technology (
Finally, similar to other comments that identified terms in regulatory language that appear too restrictive (see preceding comment and response), the Agency does recognize that a material can still be a non-waste even if there are some negligible or
The acceptable C&D wood is sourced from contractors, homeowners, community collections, and other typically small generators who segregate and/or collect clean wood from C&D sites. Chip and grind facilities do not process comingled C&D, but they may need to remove
Another commenter states that they use fuel from a “chip and grind” operation that receives and then resizes clean cellulosic biomass, and material from contractors, small operators, and generators of source-separated wood. These materials are sorted prior to receipt at the chip and grind processor, and therefore there are no fines that require screening or further separation. The EPA should not require fines removal at chip and grind facilities that receive and process only source separated C&D wood, since the fines have been left behind with the non-wood C&D debris during the positive pick process.
According to the data submitted by one commenter for five chip and grind facilities that do not remove fines, lead concentrations for its biomass fuel loads were all significantly lower (with the highest concentration at 104 ppm, followed by 77 ppm, 48 ppm, 29 ppm, and 32 ppm) than the upper end for wood and biomass (340 ppm). Based on the sampling data and the fact that the C&D wood has been pre-sorted via positive sorting before reaching the chip and grind processing facility, we agree with the commenters that chip and grind processors should not be considered negative sorting facilities when they conduct further sorting to remove small amounts of unwanted materials. Therefore, we have revised the best management practice description with respect to lead elimination requirement for positive sorters to include facilities “. . . that receive and process positive sorted C&D wood”. See revised 40 CFR 241.4(a)(5)(i).
Development of a preset level of contaminant concentrations is an activity to determine appropriate standards under the CAA. Under the NHSM framework, the material's contaminant concentration must be comparable to, or less than, the traditional fuel it is replacing which is one part of the process for determining whether the material has been discarded before or during its combustion. In this case, clean wood and biomass are the traditional fuels that are being replaced by processed C&D wood. Clean wood and biomass do not contain pentachlorophenol (non-detect levels) and, therefore, processed C&D wood may not contain measureable levels of pentachlorophenol. Otherwise, any processed C&D wood containing pentachlorophenol would be considered to be burned for destruction, which is indicative of discard. For further discussion on the Agency's approach to contaminant comparisons, see the response to comment in section V.6.b.
The EPA also recognized that including resinated wood in a fuel mix actually decreases hazardous air pollutant emissions. 76 FR 15502. While not relevant to a determination of whether the contaminant legitimacy criterion is met, this impact on emissions is a relevant factor to be balanced when making a non-waste determination under 40 CFR 241.4. 78 FR 9112, 9157 (February 7, 2013).
As a component of a processed fuel, resinated wood is not being combusted to discard it. On the contrary, as
The Agency has determined that the additional factors discussed in the proposal are appropriate and has adopted that rationale for the final rule. Thus, resinated wood may remain in C&D wood prior to processing for this categorical non-waste listing. This determination is based in part on the fact that future rules will limit levels of formaldehyde in wood products, and will in effect, also reduce the levels of formaldehyde in processed C&D wood. Also and more importantly, information submitted to the Agency states that some processors choose to include resinated wood in processed C&D based on combustor specifications for a higher Btu value fuel. This demonstrates that resinated wood is a valuable fuel and is not burned for destruction. Thus, the final rule allows flexibility for processors to choose whether they will exclude or remove any resinated wood prior to processing the C&D debris.
Regarding the citations provided in support of commenters' rationale for not requiring exclusion or removal of formaldehyde, clarification is needed. The citation at 76 FR 80483, December 23, 2011, discussed the Agency's proposed rationale for listing resinated wood as a categorical non-waste. However, the fact that the Agency finalized a listing for resinated wood as a categorical non-waste at 40 CFR 241.4(a)(2) (see also final rule at 78 FR 9155, February 7, 2013), has no relevance to a determination of whether it is appropriate to allow elevated levels of formaldehyde from resinated wood in an entirely different industrial process. In the proposal at 79 FR 21015, April 14, 2014. the Agency reviewed the rationale behind the categorical non-waste listing for resinated wood, which discussed that, although the situation appears similar to the categorical non-waste listing for resinated wood in 40 CFR 241.4(a)(2), details surrounding use of the two NHSMs as fuel are not the same. In the case of resinated wood, as defined in 40 CFR 241.2, the Agency determined that energy recovered from the combustion of manufacturing process residues and off-specification resinated wood is integrally tied to the industrial production process in the furniture manufacturing industry. The Agency is not aware of an industrial process that is reliant upon C&D wood for its energy needs.
The Agency also disagrees with the suggested grouping approach included as reasoning for allowing resinated wood to be present in C&D wood. The commenter suggested that when formaldehyde is grouped with other VOCs and SVOCs and then compared to levels of this contaminant grouping in C&D wood, the levels are comparable to coal.
Finally, while it is true that the Agency has recognized that including resinated wood in a fuel mix actually decreases some hazardous air pollutant emissions, the purpose of the discussion at 76 FR 15502, March 21, 2011, was to reiterate that the legitimacy criterion is based on the level of contaminants in the secondary material itself, and not based on comparing the differences in emissions. That said, the Agency agrees with the comment that, although not relevant to a determination of whether the contaminant legitimacy criterion is met, the impact on emissions is a relevant factor to be balanced when making a non-waste determination under 40 CFR 241.4. The Agency maintains that the benefits of burning kiln-dried wood not only provides higher heating value, but also more consistent moisture content which lends to more efficient combustion and thus reduced emissions of certain contaminants.
Because CCA-treated wood can represent up to 30 percent of the C&D waste stream and, unlike formaldehyde levels which are expected to decrease over time due to future rules to limit formaldehyde levels in resinated wood, levels of arsenic and chromium are expected to increase with continued use of CCA-treated lumber or other copper, chromium, or arsenical preservatives. As a result, the Agency has determined that CCA-treated wood must be excluded or removed from C&D debris to ensure that levels of arsenic and chromium in processed C&D wood remain comparable to or lower than levels in clean wood and biomass.
The Florida evidence demonstrates that processors who train their employees to visually recognize treated wood are successful in excluding or removing CCA-treated wood.
The proposition that XRF technology and PAN indicator stains would increase the cost and time associated with processing C&D wood is not relevant in the Agency's determination to not require their use, although processors may use such tools. The main point is that these technologies are not necessary to remove excessive contaminants from the processed material when visual identification is sufficient.
Rather than prescribing training requirements that may not be applicable to all C&D processing facilities (
The mechanism for determining if C&D processors have trained their operators as required is when the processor certifies, in the written certification statement that it has used trained operators in its sorting operations, as well as through the processor's records of training. For example, should the processed C&D wood be found to contain contaminants that are not comparable to clean wood and biomass, then it may be an indication that the processor has not trained its operators as confirmed by the certification statement. See regulatory language located at 40 CFR 241.4(a)(5)(iii), which states that “[p]rocessors must train operators to exclude or remove the materials as listed in paragraph (a)(5) of this section from the final product fuel. Records of training must include dates of training held and must be maintained for a period of three years.”
Although contracts and purchase agreements indicate a commitment to quality, specifications can vary according to the needs of one combustor versus another with respect to the extent and type of contaminant removal required. More importantly, the contracts and purchase agreements that the Agency has seen do not show that C&D wood has been processed according to any particular best management practices and, consequently, cannot ensure that the resulting material is not a waste when combusted. As one commenter had noted, a mechanism must be in place which provides assurance that C&D wood is processed consistently and according to best management practices such that the final product meets the legitimacy criteria. The Agency concurs with that comment and is requiring combustors to obtain a written certification statement from the final processor as part of every new or modified contract, purchase agreement, or other legally binding document. This written certification statement must state that the processed C&D wood has been sorted by trained operators in accordance with best management practices. See new requirement at 40 CFR 241.4(a)(5)(iv).
The Agency disagrees that a requirement for a combustor to maintain a contract or purchase agreement in its records poses any additional burden on the regulated combustion source, since these documents are typically retained for other business purposes. The combustor would need only to ensure that the contract or purchase agreement contains the written certification statement as required by the regulations at 40 CFR 241.4(a)(5)(iv) and maintain in its records according to its existing regulatory obligations under 40 CFR parts 60 and 63.
The Agency does agree, however, with the suggestion to specify how often and who must submit the certification. This allows the combustor and regulatory personnel to determine where a shipment of inadequately processed C&D wood came from. For instance, upon sampling the processed C&D wood, results indicate that it contains high levels of one or more contaminants which can be traced back to a specific processor for investigation of compliance with best management practices. Thus, every new or modified contract, purchase agreement, or other legally binding document must include a statement by the final processor that the processed C&D wood has been sorted by trained operators in accordance with best management practices. See new regulatory language at 40 CFR 241.4(a)(5)(iv).
Although a third party sampling program could provide further assurance that contaminated material has been removed from the fuel stream, the Agency cannot promote such a requirement for combustors given the data which supports this categorical non-waste listing for processed C&D wood.
This is consistent with how any major source or area source combustion unit would document that the NHSM they are burning satisfies the 40 CFR part 241 requirements for non-wastes. For example, if a combustor chooses not to comply with the conditions of the categorical non-waste listing for C&D wood under section 241.4(a)(5), then it could burn C&D wood on a case-by-case basis provided the combustor documents in its records that the processed C&D wood has been sufficiently processed per section 241.2 and that the legitimacy criteria have been met according to section 241.3(d). The combustor would still be required to maintain such documentation according to its applicable Federal recordkeeping requirements (
A trade organization, Portland Cement Association (PCA), submitted comments and information related to how cement kilns use C&D wood. Their comments are unique in that they base their responses to the proposal on the operation and capabilities of cement kilns instead of the criteria that must be met for listing an NHSM as a categorical non-waste. For example, instead of presenting information on whether the conditions of the categorical listing are appropriate, PCA comments that cement kilns have continually shown through decades of testing that the inherent manufacturing process design is conducive to fully utilizing the energy value in the alternative fuel, as the process is based on the high-efficiency combustion in the kiln. Alternative fuels that are useable in the cement industry may also contain other raw material constituents, which increase the effectiveness of being able to use a wider range of heating values that may not be useable in other combustion processes. Specific comments from the trade organization are discussed below followed by Agency responses.
This final rule applies to cement kilns, as well as all other facilities that wish to burn processed C&D wood for reasons discussed in the rule. Thus, cement kilns that wish to take advantage of the categorical non-waste listing for C&D wood under 40 CFR 241.4(a)(5), must meet all of the conditions in the rule regardless of the unit's capabilities. Cement kilns may also proceed on a case-by-case basis, but would need to determine whether the processed C&D wood has been sufficiently processed per 40 CFR 241.2 and whether the legitimacy criteria have been met per 40 CFR 241.3(d).
PCA did provide contaminant data for solid traditional fuels that are used by cement kilns, by grouping coke, coal, clean wood, and biomass together and then compared contaminant concentrations to processed C&D wood. The grouped data show that even when metals are grouped based upon their behavior in a cement kiln, the SVM group, which includes lead, still has a higher concentration in processed C&D wood than in the solid traditional fuel SVM group. The same is also true for the volatile organic compound group. Although the concentrations presented may be considered to be within a small acceptable range,
The April 14, 2014 proposed rule described paper recycling residuals (PRRs) in detail (79 FR 21010-17), explained the status of PRRs under current rules, discussed comments received during previous proceedings, as well as the scope of the proposed non-waste listing (79 FR 21017-18). The proposed rationale for the listing is found in the proposal at 79 FR 21018-20 and is summarized and incorporated into this final rule, along with all sources referenced in that discussion and cited therein. The final decision in this rule is based on the information in the proposal and supporting materials in the rulemaking record. Any changes made to the final rule are based on the rationale, as described below.
PRRs are recovered from the paper recycling manufacturing process at paper recycling mills. The feedstock used in paper recycling manufacturing process is post-consumer paper, such as
This final rule addresses only the PRR material that may be used as a non-waste fuel and be burned under CAA section 112. These PRRs consist of wet strength short fibers that are not suitable to be recycled into paper products but are essentially the same as the bark, biomass and/or coal that are burned, or may be burned, by paper recycling mills. The short fiber material is combusted as a product because it is not discarded by the paper recycling mills and meets the legitimacy criteria,
In addition to the wet strength short fibers that are recovered from the paper recycling process and used as fuel, fine screens remove other non-fiber packaging material that cannot be used for making paper products, including polystyrene foam, polyethylene film, other plastics, waxes and adhesives, dyes and ink, clays, starches, and other filler and coating additives (generally associated with corrugated paper products). Small amounts of these non-fiber materials may remain in the product fuel even though the fuel still contains contaminants comparable to the fuel burned by the recycling plants.
To ensure that excess contaminants are removed and that the material meets the legitimacy criteria when combusted, the EPA is issuing a final rule that provides that the material covered by the categorical listing consists primarily of wet strength short fibers that contain only small amounts of non-fiber materials including polystyrene foam, polyethylene film, other plastics, waxes, dyes and inks, clays, starches, and other filler and coating additives. PRRs that are not composed primarily of unsuitable wood fibers and contain more than small amounts of these non-fiber materials would be considered waste fuels and would not be eligible for this categorical listing. Thus, not all residuals may be properly burned as a product fuel.
Paper recycling mills generate between 450,000 and 600,000 tons of PRRs per year. Approximately 30 percent of the PRRs (135,000 to 180,000 tons) generated are burned for their fuel value at 15 to 20 different paper recycling mills.
The Agency previously understood PRRs to be a term industry commonly used to refer to Old Corrugated Container (OCC) rejects.
In the final regulation, the EPA has determined that not all types of PRRs may be burned as a non-waste (product) fuel, as further explained below. The PRRs that are eligible to be burned as product fuels are limited to the wet strength short wood fibers that are essentially the same as the wood and biomass products burned by the paper recycling industry and contain only small amounts of certain non-wood fibers. Thus, based on the rulemaking record, this final rule represents a further refinement of PRRs that may be burned as a product fuel.
In the March 21, 2011 NHSM final rule, the EPA stated that OCC rejects are not discarded when used within the control of the generator, such as at pulp and paper mills, since these NHSMs are part of the industrial process. In addition, we stated that the data submitted during the comment period would seem to suggest that these materials would or could meet the legitimacy criteria. For example, the data stated that the contaminant levels in these materials are comparable to, if not less than, those in traditional fuels used at pulp and paper mills. With respect to the meaningful heating value criterion, we noted that, although the Btu value of OCC rejects, as fired, is lower than 5,000 Btu/lb, it can still meet this criterion if it can be demonstrated that the combustion unit can cost-effectively recover energy from these materials. Last, the information submitted also demonstrated that OCC rejects are managed as a valuable commodity as they are managed in the same manner as the analogous fuel—bark (76 FR 15456-7, March 21, 2011). Therefore, the Agency generally concluded that OCC rejects burned as a fuel within the control of the generator
Under the February 2013 final rule, we stated that PRRs (which include OCC rejects) are not discarded when burned under the control of the generator. Also, after publication of the March 21, 2011 final rule and during finalization of the February 7, 2013 final rule, we received additional information regarding the cost effectiveness of PRRs used as a fuel, including the amount of PRRs replacing traditional fuels at paper recycling mills and percentages of residuals generated that are combusted as a fuel.
In the April 14, 2014 proposed rule (79 FR 21005), the Agency proposed to categorically list PRRs, including OCC rejects, as a non-waste fuel for those paper recycling mills whose on-site boilers are designed to burn solid fuels. As stated in the proposal, PRRs generated during the paper recycling manufacturing process vary in composition. However PRRs used as fuel are composed primarily of the wet strength and short wood fibers that cannot be used to make new paper and paperboard products. Although PRRs are generated at more than 100 paper recycling mills, only between 15 and 20 mills can burn those materials as fuel because their boilers are designed to burn solid fuel. The majority of paper recycling mills cannot burn solid fuels because their boilers are designed to burn natural gas, and thus, usually send their PRRs to landfills. Data and information submitted to the Agency by industry demonstrated that PRRs are not discarded when used as a fuel on-site within the control of the generator. Further, the data and information indicated that all three legitimacy criteria are met.
This final rule adopts the listing of PRRs, including OCC rejects as categorical non-wastes, but makes several changes to the definition under 40 CFR 241.2 and the listing of PRRs under 40 CFR 241.4 to clarify that not all residuals are to be burned as a product fuel. Based on the rulemaking record, the final rule represents a further refinement of PRRs that may be burned as a non-waste product fuel and not are not discarded.
Specifically, the proposed rule definition had stated “
The definition of PRRs is revised in the final rule to limit the listing to those PRRs composed of wet strength, short wood fibers, with only small amounts of non-fiber materials remaining. The definition also clarifies that PRRs are more appropriately defined as secondary materials
Use of the term co-products could infer that PRRs constitute a product fuel that has undergone processing through the paper recycling manufacturing process. Rather, the paper recycling manufacturing process generates wood fibers that are used to make new paper and paperboard products. PRRs are a secondary material or “byproduct” of that manufacturing process and are not discarded when used as a fuel within control of the generator or sent off-site to other paper recycling mills within the industry. Essentially, the PRRs are wood fibers used to make paper but, due to their inferior quality (fiber size), cannot be used in the paper making process. However, they may be combusted as a fuel.
The final categorical definition thus states: “
Revisions are also made to the language for the categorical listing of PRRs under 40 CFR 241.4: Non-waste Determinations for Specific Non-Hazardous Secondary Materials When Used as a Fuel. The proposed 40 CFR 241.4(a)(6) had stated “Paper recycling residuals, including old corrugated cardboard rejects, generated from the recycling of recovered paper and paperboard products and burned on-site by paper recycling mills whose boilers are designed to burn solid fuel.” As discussed in the detail in section V.B.4 of this preamble, PRRs with lower heating values would not be considered discarded since recycling mills' boilers can cost effectively recover energy from fuels because of the boiler design itself. The term, “on-site,” is deleted to clarify that PRRs can be combusted at any paper recycling mill with boilers designed to burn solid fuel, whether on-site at the generating mill, or transferred to another off-site paper recycling mill. Finally, the language “ . . . including old corrugated cardboard rejects generated from the recycling of recovered paper, and paperboard products” is revised to parallel the definition of PRRs discussed above.
Thus, the final categorical rule listing states: Paper recycling residuals generated from the recycling of recovered paper, paperboard and corrugated containers and combusted by paper recycling mills whose boilers are designed to burn solid fuel.
The rationale for this final rule is discussed in sections V.B 4 and 5 of this preamble.
This section discusses the reasoning provided in the proposed rule and the reasons for the EPA's final determinations for the categorical listing of PRRs. EPA adopts the reasoning in the proposed rule and further explains it in this preamble. Further explanations for the Agency's decision are provided in the Response to Comments below. The proposal, this section, and the Response to Comments all constitute the Agency's final determination supporting this rule.
When deciding whether an NHSM should be listed as a categorical non-waste fuel in accordance with 40 CFR 241.4(b)(5), the EPA first evaluates whether or not the NHSM has been discarded in the first instance and, if not so discarded, whether or not the material could be considered discarded because it is not legitimately used as a product fuel in a combustion unit.
Based on the rulemaking record, as discussed below, the Agency has determined that PRRs used as a fuel are secondary materials recovered from the paper recycling manufacturing process and are not discarded when burned within control of the generator or sent off-site to other paper recycling mills within the industry.
The paper recycling process is grouped generally into three steps for purposes of identifying where residuals are generated. In the first step, bales of the incoming post-consumer paper enter a pulper where the paper and fiber are wetted and dispersed. A “debris rope” or “ragger” continuously withdraws strings, wires, and rags that could otherwise damage the processing equipment. Recovered metals may be sold to metals recovery facilities, but other materials removed by the ragger are landfilled because they produce a heterogeneous mixture.
In the second step, materials that remain in the pulper can either pass to a junk tower for removal of heavy materials and continue to a drum screen for removal of lighter materials; or go directly to coarse screens. For those materials that go to the coarse screens, the resulting rejects may pass through an air separator and/or a high efficiency cyclone, which further removes materials based on size, shape and density, such as plastic and unsuitable paper fibers (
In the final step, a series of fine screens remove any remaining material that cannot be used to make paper or paperboard products. These rejected materials include unusable paper fiber fines, clays, starches, waxes and adhesives, other plastics, filler and coating additives, and dyes and inks. During this step, reject materials may either pass along to the wastewater treatment system or become part of the PRR stream and be used as a fuel. For example, for some grades of reject materials that are dispersed and small, such as dyes and inks, waxes, and coating adhesives generated from recovered magazines and other papers, these materials will not be removed by fine screens and therefore, enter the wastewater treatment system. In contrast, for other grades, these light reject materials are captured in fine screens and can be used as a fuel.
Thus, PRRs are generated at various steps of the paper recycling process, with the second step producing the bulk of PRRs (
In determining whether PRRs used as a fuel are more product-like than waste-like, we considered the following attributes:
• PRRs are generated as a secondary material from the paper recycling process that makes new paper and paperboard products and consist primarily of unsuitable wood fibers that are never discarded within that paper making process.
• When these PRRs are combusted in mill boilers that burn solid fuel, they recover meaningful heating value;
• Paper recycling mills that can combust PRRs burn a significant amount of what they generate on-site: 55 percent-100 percent.
• PRRs are used to replace traditional fuels by as much as 25 percent. Accordingly, the wet strength short fiber PRRs, when generated at the recycling facility, are more product-like than waste-like.
As discussed in section V.B.5. of this preamble below, the Agency lacked sufficient information to determine that, after the recycling process described above, PRRs sent off-site for energy recovery to facilities outside the paper recycling industry are not discarded. The Agency stated in the proposal that it was requesting additional information for PRRs that are burned off-site which demonstrates how they: (1) Are managed as a valuable commodity (from point of generation at the paper recycling mill to insertion at the off-site combustor, to show that discard is not occurring); (2) have a meaningful heating value; (3) contain contaminants at levels comparable to or lower than those in traditional fuel(s) which the combustor is designed to burn; and (4) the types of facilities that combust these PRRs. The agency received general statements that PRRs are an important part of paper mills' fuel mix and that third party sellers and purchasers classify PRRs as fuel. These general statements did not provide the detailed information the EPA needed to make a reasoned determination that PRRs sent off-site to entities outside of the paper recycling industry for combustion constituted discard or product fuel use.
Combustion of PRRs off-site and within the paper recycling industry, however, is different. For these facilities the Agency examined the data in the record from previous rulemakings as well as comments received on the proposal. The Agency has determined that the listing includes PRRs generated by paper recycling mills that transfer that material off-site for combustion at the estimated 15-20 paper recycling mills that have the solid fuel boilers capability of burning PRRs for energy recovery.
Regarding off-site use, the EPA has discussed in previous NHSM rulemakings that transferring secondary materials between companies or facilities does not necessarily mean that the material has been discarded (see 76 FR 15500, March 21, 2011). The PRRs transferred off-site to other paper recycling facilities with the capability to combust these fuels are utilized in the same manner as self-generated paper recycling residuals, such that they are legitimately burned in solid fuel boilers that are designed to burn wet fuels (see V.B.4.b. of this preamble for a discussion of legitimacy criteria for off-site combustion), with mills optimizing their operation around boiler design.
In determining whether to list PRRs as a categorical non-waste fuel in 40 CFR 241.4(a), the Agency evaluated the legitimacy criteria in 40 CFR 241.3(d)(1)—that is, whether it is managed as a valuable commodity, whether it has a meaningful heating value and is used as a fuel in a combustion unit to recover energy, and whether contaminants or groups of contaminants are at levels comparable to or less than those in the traditional fuel the unit is designed to burn. Materials not meeting these criteria are considered discarded and thus a solid waste.
Regarding the first legitimacy criterion, PRRs that are utilized as a fuel are managed similarly to traditional fuels that are burned at paper recycling mills such as hogged wood, other clean biomass, or coal. PRRs are also managed as a valuable commodity when they are utilized off-site as a fuel within the paper recycling industry. Some paper recycling mills store PRRs in containers (
For PRRs utilized as a fuel at off-site paper mills, PRRs are managed similarly to those generated on-site.
With respect to the second legitimacy criterion, PRRs, as fired and generated, average 3,700 Btu/lb (or on a dry basis, average 9,100 Btu/lb).
The EPA finds that the data in the record and the description of the combustion process of the particular combustors used in the paper recycling industry confirm that paper mill boilers cost-effectively recover energy from PRRs used as fuel. These solid fuel boilers are designed to burn wet fuels, and have over-fire and/or under-grate air that assists in the efficient burning of wetter fuels. These design characteristics allow the boilers to burn PRRs (as well as cellulosic biomass fuels) that have high moisture content.
The meaningful heating values for PRRs generated at off-site paper recycling mills are consistent with PRRs generated on-site.
See also section V.B.6.a.i. for a discussion of data on facilities combusting PRRs greater than 3, 700 Btu/lb, and options for facilities combusting PRRs that are less than that Btu/lb level.
For the third legitimacy criterion, a contaminant comparison was conducted to capture data that is representative of all PRR fuel types within the EPA's Boiler MACT Database. The contaminant data include PRRs
As discussed in the proposed rule (79 FR 21019, April 14, 2014), and adopted for the final rule, contaminant concentrations of those constituents found in Table 2 of this preamble in PRRs were compared to the levels found in coal and biomass, since both of these traditional fuels can be burned in boilers at paper recycling mills (see discussion below regarding combustion of coal). Data show that PRRs, whether combusted at on-site or off-site paper recycling mills, meet the contaminant legitimacy criterion. The only reported instance of PRRs containing a contaminant at levels approaching the highest levels in coal and biomass is a chlorine concentration at a mill burning OCC rejects. However, the highest reported value for chlorine in PRRs was 7,310 ppm, which is still below the highest reported value for chlorine in coal (9,080 ppm). Therefore, the contaminant concentrations for these contaminants are comparable to the traditional fuels that the boilers are designed to burn.
With regard to organic HAP present in PRRs, although no specific data is available on the concentration of these contaminants in PRRs, limited data has been published on TCLP extracts of OCC rejects that include several organic HAPs. With the exception of toluene, which was found at trace levels ranging from <0.001 to 0.004 mg/L, no other HAPs were detected in the TCLP extracts for OCC rejects.
The contaminant data submitted also compared PRRs to coal as the traditional fuel for comparison. As stated in section V.B.1. of this preamble, PRRs may represent between 20 to 25 percent of the total solid fuel burned in their solid fuel boilers, thus, units combusting PRRs may also be designed to burn other solid fuels such as coal. As shown in Table 2 of this preamble, PRR concentrations were comparable to those in coal as well as clean wood/biomass. Under the final rule, therefore, units that are designed to burn clean wood/biomass and are combusting PRRs in boilers that recover meaningful heating value from those residuals, may
The proposed rule identified several issues pertaining to the listing of PRRs as categorical non-wastes and requested comment on those issues which are summarized below.
No information was received from industry regarding the percentage of these non-fiber materials. Lacking such information, the Agency finds that PRRs with higher amounts of non-fiber materials would have a lower heating value. Combustion of more than small amounts of these materials with these low heating values are discard of those materials and burning of a waste fuel. The Agency is thus revising the definition of PRRs to clarify that the categorical non-waste listing applies only to PRRs composed primarily of wet strength and short wood fibers that do not contain more than small amounts of polystyrene foam, polyethylene film, other plastics, waxes and adhesives, dyes and ink, clays, starches, and other filler and coating additives.
Based on information received, and examination of the few cases in the boiler database of foreign materials present in OCC rejects undergoing recycling,
While the information generally indicates that these PRRs are managed much the same way as those burned on-site, it is based on only two cases and lacks sufficient detail to determine that PRRs when sent off-site for energy recovery continue to meet the legitimacy criteria and are not discarded. Therefore, we requested additional information for PRRs that are burned off-site which demonstrates how they: (1) Are managed as a valuable commodity (from point of generation at the paper recycling mill to insertion at the off-site combustor, to clearly show that discard is not occurring); (2) have a meaningful heating value; (3) contain contaminants at levels comparable to or lower than those in traditional fuel(s) which the combustor is designed to burn; and (4) the types of facilities that combust these PRRs.
Commenters did not provide data regarding how that material meets other legitimacy criteria including management of the fuel as a valuable commodity and meaningful heating value. In particular, the Agency did not receive information that facilities outside the paper recycling industry combusted PRRs in the solid fuel boilers designed to burn wet fuels characteristic of paper recyclers. The Agency has determined that the listing be revised from the proposal to include PRRs generated by paper recycling mills that do not have the capability to combust the materials on-site, but are transferred off-site for combustion at the estimated 15-20 paper recycling mills that do have the solid fuel boilers capable of burning PRRs for energy recovery. The PRRs transferred off-site to other paper recycling facilities with the capability to combust these fuels are utilized in the same manner as self-generated paper recycling residuals
The mills' solid fuel boilers are designed to burn wet fuels, with each mill optimizing its operation around boiler design. Typical boilers used include stoker fired and fluidized bed combustors, which often have over-fire and/or under-grate air that assists in the efficient burning of wetter fuels. If the material being fed to the boiler is too dry, the combustion temperature can become too hot, requiring operational adjustments. Consistently wet materials are handled well in these boilers, leading to fewer temperature swings and minimized boiler tuning adjustments.
PRRs are also analogous to the primary fuels—hog fuel and bark—used in solid fuel boilers at paper recycling mills in that they both have high moisture content, usually >40 percent, and can have Btu values below 5,000 Btu/lb, as fired. However, PRRs can also have Btu values higher than 5,000 Btu/lb, depending upon the amount of moisture that has been removed (
To further understand the variability of the PRR's heating value, the Agency requested information regarding the percentages of non-fiber materials (
However, no information was received from industry regarding the percentage of these non-fiber materials as the Agency requested. Lacking such information, the Agency finds that PRRs with higher amounts of non-fiber materials would have a lower heating value (
The Agency disagrees that heating value is irrelevant. As discussed in section V.B.4., based on all of the available information, including the fact that PRRs are primarily wood fibers, the Agency has determined that PRRs with heating values averaging 3,700 Btu/lb (or on a dry basis, averaging 9,100 Btu/lb), whether generated on-site or combusted at off-site paper recycling mills that burn solid fuel, meet the meaningful heating value legitimacy criterion and are burned as a product fuel. PRRs that average less than 3,700 Btu/lb (9,100 Btu/lb dry basis) would not have meaningful heating value for purposes of this categorical listing, thus, the listing would not apply to those materials.
The EPA realizes that some facilities may be combusting PRRs that average less than 3,700 Btu/lb. However, data in the record indicates that a majority of facilities combust PRRs with heating values greater than 3,700 Btu/lb. Technical data on PRRs cited by industry
Facilities combusting PRRs that do not meet the average 3,700 Btu/lb meaningful heating value criterion for the categorical PRR non-waste listing have several options to continue to burn those PRRs. Combustors may take additional measures to meet the average 3,700 Btu/lb level by further drying the PRRs or removing low heat content non-fiber material. Combustors burning lower BTU value PRRs may also make self-determinations under 40 CFR 241.3(b) that the material is a non-waste fuel and meets legitimacy criteria including meaningful heating value. Finally, combustors can continue to burn those lower BTU PRRs under the section 129 standards of the CAA.
The commenter went on to say, however, that the EPA does not need to be concerned about other materials contained in PRRs, and any unacceptable contaminant concentrations related to such materials. For sales transactions that are direct with suppliers, the mills and suppliers rely on the Scrap Specification Circular
While the EPA agrees that, under certain circumstances, PRRs may be transferred as a product fuel within the paper recycling industry (and are not discarded), the Agency disagrees with the comment's characterization of the AMC I case. AMC I does not directly apply in this instance. The AMC I holding stated that material reclaimed in a continuous industrial process could not be a waste. It did not specifically cover materials transferred between facilities, even in the same industry, particularly a material reclaimed from recycled paper but then used for another purpose—burning as a fuel.
Several mills have also partnered with local utilities that can use the PRRs as fuel. Further, requiring an off-site facility to petition the EPA before it could acquire and burn PRRs will add significant administrative costs. Small paper mills typically do not have solid-fuel boilers and therefore look to off-site partners to find appropriate uses for their PRRs.
The Agency clearly stated its need for additional information regarding residuals that are burned as fuel at facilities not under the control of the generator. The EPA requested detailed information about how PRRs are managed as a valuable commodity (from point of generation at the paper recycling mill to insertion at the off-site combustor); have a meaningful heating value; and contain contaminants at levels comparable to or lower than those in traditional fuel(s) which the combustor is designed to burn.
General statements that PRRs are an important part of the fuel mix outside the paper recycling industry, and that third party sellers and purchasers classify PRRs as fuel, is not the relevant consideration for deciding whether material, even a fuel, is burned as a waste.
Moreover, merely saying that a material is considered a fuel does not address the issue of whether that fuel is a waste. Wastes may be burned as fuels, but they still are wastes. The commenters did not provide data regarding how that material meets other legitimacy criteria including management of the fuel as a valuable commodity and meaningful heating value. In particular, the Agency did not receive information that facilities outside the paper recycling industry combusted PRRs in the solid fuel boilers designed to burn wet fuels characteristic of paper recyclers. While the EPA may accept the low Btu value of PRRs as a legitimate product fuel for paper recycling facilities, the same kind of low Btu value fuel could be a waste at other facilities. At those facilities, any low Btu value material could simply be thrown in as a waste.
In addition, the EPA rejects arguments that the Agency should rely on air permit emissions limitations in determining whether material is a waste. Prior to establishing emission limits, the EPA first needs to determine whether the material is discarded in order to decide whether boiler emission standards (under CAA section 112 regulations) or CAA section 129 standards would apply.
PRRs sent off-site for combustion to facilities outside the paper recycling industry will require submittal and approval of a non-waste petition under 40 CFR 241.3(c) to be burned at CAA section 112 facilities.
The arguments that cement kilns are capable of handling a wide variety of fuels without the need for extensive processing that some other facilities require and that processing needs to be flexible and appropriate to the receiving combustion unit could demonstrate that cement kilns can burn waste fuels as well as non-waste fuels. The commenter also misunderstands the “processing” requirements under 40 CFR part 241 standards. Under 40 CFR 241.3(b)(4), when discarded, NHSMs must be processed
To reiterate, these comments generally confirm that cement kilns are capable of burning wastes as fuels. If they do, they should be regulated under section 129 of the Clean Air Act.
It is our understanding that the EPA does not intend to distinguish between residuals from recycling paper and residuals from recycling old corrugated containers and that the EPA recognizes that these residuals are composed primarily of fibers but that there could include other materials from the paper and corrugated cardboard bales. As the EPA has noted: “For example, use of old corrugated cardboard (OCC) rejects (clay, starches, other filler and coating materials, as well as fiber) are not discarded when used within the control of the generator, since these secondary materials are part of the industrial process. OCC rejects can include, and are usually burned in conjunction with, other fuels (such as bark) at pulp and paper mills that recycle fibers. 76 FR at 15472.
To apply this understanding to both paper and paperboard, we suggest the following revision to the definition: Paper recycling residuals means the co-product material generated from the recycling of paper, paperboard, and corrugated containers and is composed primarily of wet strength and short wood fibers that cannot be used to make new paper and paperboard products.
As discussed in the comment above regarding meaningful heating value, no specific information was received from industry regarding the percentage of these non-fiber materials as the Agency requested. Lacking information to the contrary, the Agency finds that PRRs with higher amounts of non-fiber materials would have a lower heating value. Combustion of materials with low heating values would be considered discard of those materials and burning of a waste fuel. The Agency is thus revising the proposed definition of PRRs and clarifying the previous statements at 76 FR 15472, March 21, 2011, regarding non-fiber material contained in OCC rejects to make clear that the categorical non-waste listing applies only to PRRs composed primarily of wet strength and short wood fibers that do not contain more than small amounts of polystyrene foam, polyethylene film, other plastics, waxes and adhesives, dyes and ink clays, starches, and other filler and coating additives.
The definition also clarifies that PRRs are more appropriately defined as secondary materials
The revised definition of
The April 14, 2014 proposed rule described CTRTs in detail, explained the status of CTRTs under current rules, discussed comments received during previous proceedings, and discussed the scope of the proposed non-waste listing (79 FR 21021-23). The proposed rationale for the listing is found in the proposal at 79 FR 210 23-28 and is summarized and incorporated into this final rule, along with all sources referenced in that discussion and cited therein. The final decision in this rule is based on the information in the proposal and supporting materials in the rulemaking record. Any changes made to the final rule are based on the rationale, as described below.
Railroad ties are typically comprised of North American hardwoods that have been treated with creosote. Creosote was introduced as a wood preservative in the late 1800's to prolong the life of railroad ties. Creosote-treated wood ties remain the material of choice by railroads due to their long life, durability, cost effectiveness, and sustainability. As creosote is a by-product of coal tar distillation, and coal tar is a by-product of making coke from coal, creosote is considered a derivative of coal. The creosote component of CTRTs is governed by the standards established by the American Wood Protection Association (AWPA). AWPA has established two blends of creosote, P1/13 and P2.
CTRTs are railroad crossties removed from service and processed prior to being used as a fuel. Approximately 17 million crossties are removed from service each year. About one third of the removed CTRTs are used for landscaping, with the majority of the remaining two thirds used for energy recovery. Because of its high energy content, CTRTs can be used for heat and energy recovery in combustion units as a nonhazardous biomass alternative to fossil fuel.
Most of the energy recovery with crossties is conducted through three parties: The generator of the crossties (railroad or utility); the reclamation company that sorts the crossties, and in some cases processes the material received from the generator;
After crossties are removed from service, they are transferred for sorting/processing, but in some cases, they may be temporarily stored in the railroad rights-of-way or at another location selected by the reclamation company. One information source stated that when the crossties are temporarily stored, they are stored until their value as an alternative fuel can be realized, generally through a contract completed for transferal of ownership to the reclamation contractor or combustor.
CTRTs are transferred to reclamation companies, typically by rail. The processing of the crossties into fuel by the reclamation/processing companies involves several steps. Metals (spikes, nails, plates, etc.) are removed using a magnet, occurring one or several times during the process. The crossties are then ground or shredded to a specified size depending on the particular needs of the end-use combustor, with chip size typically between 1-2 inches. This step occurs in several phases, including primary and secondary grinding, or in a single phase. Once the crossties are ground to a specific size, additional metal is removed if present and there is further screening based on the particular needs of the end-use combustor. Depending on the configuration of the facility and equipment, screening occurs concurrently with grinding or at a subsequent stage. Throughout the process, a non-toxic surfactant is applied to the crossties being processed to minimize dust.
Once the processing of CTRTs is complete, the CTRTs are sold directly to the end-use combustor for energy recovery. Processed CTRTs are delivered to the buyers by railcar or truck. The CTRTs are then stockpiled prior to combustion, with storage timeframes ranging from a day to a week. When the CTRTs are to be burned for energy recovery, the material is then transferred from the storage location using a conveyor belt or front-end loader. The CTRTs are combined with other biomass fuels, including hog fuel and bark. CTRTs are used to provide high Btu fuel to supplement low (and sometimes wet) Btu biomass to ensure proper combustion, often in lieu of coal or other fossil fuels.
The March 21, 2011 NHSM final rule stated that most creosote-treated wood is non-hazardous. However, the presence of hexachlorobenzene, a CAA section 112 HAP, as well as other HAP suggested that creosote-treated wood, including CTRTs, contained
In the February 7, 2013 NHSM final rule, the EPA noted that AF&PA and the American Wood Council submitted a letter with supporting information on December 6, 2012, seeking a categorical listing for CTRT combusted in any unit. The letter included information regarding the amounts of railroad ties combusted each year and the value of the ties as fuel. The letter also discussed how CTRTs satisfy the legitimacy criteria, including its high Btu value.
While this information was useful, it was not sufficient for the EPA to propose that CTRTs be listed categorically as a non-waste fuel. As explained in the proposed rule, the EPA had requested that additional information be provided to further inform the Agency as to whether to list CTRTs categorically as a non-waste fuel, and stated that if this additional information supported and supplemented the representations made in the December 2012 letter, the EPA would expect to propose a categorical listing for CTRTs.
The requested information and responses provided are outlined below.
•
•
• The traditional fuels and relative amounts (
Respondents claimed that the most comparable traditional fuel to railroad ties is fuel oil. However, they believe the question of whether a combustion unit is designed to burn a specific fuel is not relevant when the EPA makes a determination under 40 CFR 241.4(a). Specifically, the respondents claimed that the EPA has interpreted the phrase “designed to burn” to mean that a combustor that burns NHSMs as a non-waste fuel has to be able to burn the NHSM in the combustion unit, which in the case of CTRTs, would require the installation of a nozzle for the delivery of liquid fuel into the boiler, to meet the contaminant legitimacy criterion. The EPA explained that this standard is to avoid the possibility that discard could be occurring in some situations.
•
• Laboratory analyses for contaminants known or reasonably suspected to be present in creosote-treated railroad ties, and contaminants known to be significant components of creosote, specifically polycyclic aromatic hydrocarbons (
Under the proposed rule, CTRT was proposed to be listed as a categorical non-waste when combusted in units that burn both fuel oil and biomass. This limitation was based on the fact that contaminant levels for semi-volatile organics (SVOCs) are significantly higher in CTRT than levels in biomass and coal, but CTRT levels for those contaminants are lower than levels in fuel oil. In contrast, fluorine and nitrogen contaminant levels are significantly higher in CTRT than in fuel oil, but levels for those contaminants are lower than levels in biomass and coal (79 FR 21023.) Thus, only units burning both biomass and fuel oil would pass the contaminant legitimacy criteria when comparing contaminants in the NHSM to the traditional fuel.
Based on information received after the February 7, 2013 final rule stating that units were switching from fuel oil to natural gas due to lower compliance costs during operation, we also stated in the proposal that the Agency was considering another approach for CTRTs combusted in existing units at major source pulp and paper mills that had been designed to burn fuel oil and biomass, but are being modified in order to use clean fuel such as natural gas instead of fuel oil (79 FR 21028). If the EPA were to include this additional approach in the categorical listing, the CTRT could continue to be combusted only if certain conditions were met, which are all intended to ensure that the CTRTs are not being discarded. Conditions included in the proposal are:
• CTRTs must be burned in an existing stoker, bubbling bed or fluidized bed boiler;
• the CTRTs can comprise no more than 40 percent of the fuel that is used on a monthly basis;
• the boiler that burned the CTRTs must have been designed to burn both fuel oil and biomass; and
• boiler is modifying its design to also burn natural gas.
The Agency stated in the proposed rule that we did not believe that combustion of CTRT in boiler units that are currently designed to burn both biomass and fuel oil but are being modified (
The additional approach was meant to address only the circumstance where contaminants in CTRTs are comparable to or less than the traditional fuels the unit was originally designed to burn (both fuel oil and biomass) but that design was modified in order to combust natural gas. The approach was not a general means to circumvent the contaminant legitimacy criterion by allowing combustion of any NHSM with elevated contaminant levels,
For this final rule, based on comments received and information in the rulemaking record, the EPA has sufficient information to list CTRTs as a categorical non-waste fuel in combustion units that are designed to burn both biomass and fuel oil. The Agency finds that units will meet this condition if the unit combusts fuel oil as part of normal operations and not solely as part of start-up or shut-down operations.
The Agency is also adopting the additional approach outlined in the proposed rule with some revisions. Specifically, based on comments received and information in the rulemaking record, the Agency has sufficient information to list as categorical non-wastes CTRTs that are combusted in units at major source pulp and paper mills or power producers subject to 40 CFR part 63 Subpart DDDDD (Boiler MACT) that had been designed to burn biomass and fuel oil, but are modified (
• The CTRTs must be combusted in existing (
• CTRTs can comprise no more than 40 percent of the fuel that is used on an annual heat input basis.
The standard is applicable to existing units burning CTRTs that had been designed to burn fuel oil and biomass and have been modified to burn natural gas. The standard will also apply if an existing unit burning CTRTs and designed to burn fuel oil and biomass is modified at some point in the future.
Based on comments received on the proposed rule, several revisions were made in the additional approach as adopted for the final rule under section 241.(a)(7): (1) CTRTs combusted in units at power producers subject to 40 CFR part 63 Subpart DDDDD (Boiler MACT) have been added to the categorical listing; (2) the 40% fuel load limit has been changed to an annual heat input basis; (3) regulatory language was added stating that units combusting fuel oil and natural gas, as well as units that had switched from fuel oil to natural gas, must combust these materials as part of normal operations and not solely as part of start-up or shut-down operations; and (4) hybrid suspension grate boilers are added to the list of acceptable boilers and to provide further clarity regarding CTRTs combusted in “existing” stoker, bubbling bed, fluidized bed or hybrid suspension grate boilers, existing is defined as April 14, 2014, the date of issuance of the proposed rule.
See section V.C.6. Response to Comments for a further discussion of these changes.
This section discusses the reasoning provided in the proposed rule and the reasons for the EPA's final determinations for the categorical listing of CTRTs. EPA adopts the reasoning in the proposed rule and further explains it in this preamble. Further explanations for the Agency's decision are provided in the Response to Comments below. The proposal, this section, and the Response to Comments all constitute the Agency's final determination supporting this rule.
When deciding whether an NHSM should be listed as a categorical non-waste fuel in accordance with 40 CFR 241.4(b)(5), the EPA first evaluates whether or not the NHSM has been discarded in the first instance and, if not so discarded, whether or not the material could be considered discarded because it is not legitimately used as a product fuel in a combustion unit. Based on the rulemaking record, as discussed below, the Agency has determined that CTRTs are not discarded when processed and combusted in the types of units described herein.
As discussed in section V.C.1. of this preamble, crossties removed from service are sometimes temporarily stored in the railroad right-of-way or at another location selected by the reclamation company. This means that not all CTRTs originate from crossties removed from service in the same year; some CTRTs are processed from crossties removed from service in prior years and stored by railroads or removal/reclamation companies until a contract for reclamation is in place.
The December 6, 2012, letter from AF&PA states that in those cases where the railroad or reclamation company wait for more than a year to realize the value of the CTRTs as a fuel (or in landscaping) does not mean that the CTRTs have been discarded and cite 76 FR 15456, 15520 of the March 21, 2011 rule. That section of the rule addresses the management of the NHSM as a valuable commodity and states that storage of the NHSM must be within a reasonable timeframe.
While the Agency recognizes that the reasonable timeframe for storage may vary by industry, the Agency disagrees that any explanation (other than a repeat of what the rules say) has been provided of why storage that may be longer than a year is not discard, especially when they argue that CTRTs are a valuable material. Therefore, without further explanation or information from the public, the Agency concludes that CTRTs removed from service that may be stored in a railroad right of way or other location for long periods of time—that is, a year or longer, without a determination regarding their final end use (
The railroad ties removed from service are considered discarded because they can be stored for long periods of time without a final determination regarding their final end use. In order for them to be considered a non-waste fuel, they must be processed, thus transforming the railroad ties into a product fuel that meets the legitimacy criteria, or if not meeting the legitimacy criteria, would still be considered a non-waste fuel if the EPA decides so after balancing the legitimacy criteria with other relevant factors. The Agency concludes that the processing of CTRTs described above in section V.C.1. of this preamble meets the definition of processing in 40 CFR 241.2. Processing includes operations that transform discarded NHSM into a non-waste fuel or non-waste ingredient, including operations necessary to: Remove or destroy contaminants; significantly improve the fuel characteristics (
• Contaminants (spikes, nails, plates, etc.) are removed using a magnet. This magnetic removal of metals may occur several times during processing.
• The fuel characteristics of the material are improved when the crossties are ground or shredded to a specified size depending on the particular needs of the end-use combustor. The grinding may occur in one or more phases. Once the CTRTs are ground, there may be additional screening to bring the material to a specified size.
In determining whether to list CTRTs as a categorical non-waste fuel in 40 CFR 241.4(a), the Agency evaluated the legitimacy criteria in 40 CFR 241.3(d)(1)—that is, whether it is managed as a valuable commodity, whether it has a meaningful heating value and is used as a fuel in a combustion unit to recover energy, and whether contaminants or groups of contaminants are at levels comparable to or less than those in the traditional fuel the unit is designed to burn. To the extent that CTRTs do not meet one or more of the legitimacy criteria, and are
As discussed in the proposed rule and adopted for the final rule, the processing of CTRTs is correlated to the particular needs of the end-use combustor. Additional screening may take place after the grinding and shredding of the CTRTs if deemed necessary. Once the CTRTs meet the end use specification, they are then sold directly to the end-use combustor for energy recovery. CTRTs are delivered to the end-use combustors via railcar and/or truck similar to delivery of traditional biomass fuels. While awaiting combustion at the end-user, which usually takes place within a week of arrival, the CTRTs are transferred and/or handled from storage in a manner consistent with the transfer and handling of biomass fuels. Such procedures include screening by the end-use combustor, combining with biomass fuels, and transferring to the combustor via conveyor belt or front-end loader. Since processed CTRT storage does not exceed reasonable time frames and are handled/treated similar to analogous biomass fuels by end-use combustors, CTRTs meets the criterion for being managed as a valuable commodity.
As discussed in the proposal and adopted as the reasoning to support the final rule, the heating value of processed CTRTs ranges from 6,000-8,000 Btu/lb as fired, and combustion units recover energy by burning the material as fuel. In the March 21, 2011 NHSM final rule, the Agency stated that NHSMs with an energy value greater than 5,000 Btu/lb, as fired, are considered to have a meaningful heating value.
For CTRTs, the EPA compared the additional data submitted on contaminant levels by industry to analogous data for two traditional fuels: Biomass (including untreated clean wood) and fuel oil. The data the EPA received on CTRTs comes from the following three sources: M.A. Energy Resources (MAER), URS Corporation on behalf of the Association of American Railroads, and AF&PA. The information submitted by MAER included a comprehensive analysis of one CTRT sample. The sample came from a CTRT pile located at an end-use combustor. The URS Corporation report included three samples of processed CTRTs from the National Salvage facility in Selma, Alabama, and from a Stella Jones facility in Duluth, Minnesota. AF&PA also submitted documents comparing contaminant concentrations in CTRTs with traditional fuels, compiling data from various sources in these documents. The EPA considers data from these eight facilities to be representative of the CTRT universe because the composition of the creosote component of the CTRTs is the same—that is, the P2 blend of creosote, as well as the fact that multiple samples have been taken in different parts of the country at different points in the CTRT management chain.
The section below discusses determinations on contaminant comparisons in CTRTs to fuel oil and biomass. The contaminant data received on CTRTs includes information that units combusting CTRTs and fuel oil may also combust coal; determinations regarding contaminant comparisons to that traditional fuel follows the discussion on fuel oil and biomass.
As shown in Table 3 of this preamble, all contaminant concentration levels for metals are within the ranges identified for fuel oil and biomass. We note that when comparing the non-metal elemental contaminants, however, fluorine and nitrogen levels in CTRTs are not comparable to fuel oil, and semi-volatile organic compound (SVOC) levels are not comparable to biomass. Given that CTRTs are a type of treated wood biomass, and any unit burning CTRTs typically burns untreated wood, the EPA considered two scenarios that industry described.
In the first scenario, where a combustion unit is designed to only burn biomass, the EPA compared contaminant levels in CTRTs to contaminant levels in biomass. In this scenario, the total SVOC levels can reach 22,883 ppm, driven by high levels of polycyclic aromatic hydrocarbons (PAHs) and, to a lesser extent, the levels of dibenzofuran and biphenyl.
In the second scenario, a combustion unit is designed to burn biomass and fuel oil. As previously mentioned, fluorine, and nitrogen levels in CTRTs are present at elevated levels when compared to fuel oil. However, the highest levels of fluorine (100 ppm) and nitrogen (14,400 ppm) are comparable to, or well within the levels of these contaminants in biomass. Likewise, SVOCs are present in CTRTs (up to 22,883 ppm) at levels well within the range observed in fuel oil (up to 54,700 ppm). Accordingly, contaminant concentration levels for fluorine, nitrogen, and SVOCs are within the ranges identified for either biomass or fuel oil. Therefore, CTRTs have comparable contaminant levels to other fuels combusted in units designed to burn both biomass and fuel oil, and as such, meet this criterion if used in facilities that are designed to burn both biomass and fuel oil.
As stated in the preamble to the February 7, 2013, NHSM final rule, combustors may burn NHSMs as a product fuel if they compare appropriately to any traditional fuel the unit can or does burn. (78 FR 9149) Combustion units are often designed to burn multiple traditional fuels, and some units can and do rely on different fuel types at different times based on availability of fuel supplies, market conditions, power demands, and other factors. Under these circumstances, it is arbitrary to restrict the combustion for energy recovery of NHSMs based on contaminant comparison to only one traditional fuel if the unit could burn a second traditional fuel chosen due to such changes in fuel supplies, market conditions, power demands or other factors. If a unit can burn both a solid and liquid fuel, then comparison to either fuel would be appropriate.
In order to make comparisons to multiple traditional fuels, units must be designed to burn those fuels. If a facility compares contaminants in an NHSM to a traditional fuel a unit is not designed to burn, and that material is highly contaminated, a facility would then be able to burn excessive levels of waste components in the NHSM as a means of discard. Such NHSMs would be considered wastes regardless of any fuel value. (78 FR 9149)
In the first scenario, where CTRTs were combusted in units designed to burn only coal and biomass, contaminant levels in CTRTs were compared to those two traditional fuels.
In the second scenario, a combustion unit is designed to burn coal, biomass and fuel oil. As shown in Table 4 of this preamble, SVOCs are present in CTRTs (up to 22,883 ppm) at levels well exceeding those in coal and biomass but within the range observed in fuel oil (up to 54,700 ppm). Fluorine, and nitrogen levels in CTRTs are present at elevated levels when compared to fuel oil. However, the highest levels of fluorine (100 ppm) and nitrogen (14,400 ppm) are comparable to, or well within the levels of these contaminants in biomass. All other contaminants in CTRTs are comparable to those in coal.
Thus, CTRTs can be combusted in units burning coal (or other traditional fuels), but only if the unit is also designed to burn fuel oil and biomass. CTRTs have comparable contaminant levels in units designed to burn biomass fuel oil and coal, and as such, meet this criterion if used in facilities that are designed to burn those traditional fuels. (see also section V.C.6. Response to Comments regarding combustion of coal in units that switched from fuel oil to natural gas).
Industry submitted an explanatory document in response to the Agency's request.
The industry' data confirms the presence of dibenzofurans. Industry acknowledged that coal tar creosote used in preparing railroad ties may have levels of dibenzofuran up to 4.5 percent or 45,000 ppm, and dibenzofuran concentrations measured in seven samples of railroad ties previously treated with creosote ranged from 570 to 1,500 ppm. However, as stated by the industry, this compound should not be confused with dioxins or furans, which refers to a larger group of polychlorinated dibenzofurans and dibenzodioxins.
The Agency agrees with the petitioner's explanation that dibenzofuran present in the CTRTs will not result in the formation of dioxins, but as a HAP itself, dibenzofuran is still appropriate to include in the list of SVOCs for comparison to traditional fuels.
In their request for a categorical listing of CTRTs and in background information submitted subsequent to that request, industry argued that, in the context of a specific non-waste determination under 40 CFR 241.4(a), the Agency can balance the legitimacy criteria against other relevant factors in any decision to list an NHSM categorically. See 40 CFR 241.4(b)(5). Specifically, industry argued that the phrase “designed to burn” can be another relevant factor that the Agency can consider in making a decision on listing CTRTs categorically as a non-waste fuel. They argued that by conducting such balancing, the Agency could allow CTRTs to be burned as a non-waste fuel in any combustion unit that can combust biomass, whether or not the combustion unit is designed to burn fuel oil. Thus, industry requested that the Agency re-define or ignore the “design to burn” concept, as currently interpreted for the purposes of this categorical listing.
In arguing that the Agency can re-define or ignore the “design to burn” concept, industry identified additional relevant factors to be considered in a categorical listing for CTRTs. Specifically:
• CTRTs are functionally the same as other comparable traditional fuels, such as fossil fuels used in a fuel mix to maintain an appropriate Btu level for the biomass boilers, combusted in the same units and subject to the same air pollution controls.
• CTRTs are integral to the production process similar to any other fuel used and consistently have lower moisture content and higher Btu value than other biomass fuel.
• CTRTs are commodity fuels—users pay $20-$30 per ton thus industry believe that the material is not being discarded.
• High levels of PAHs in CTRTs and removal of oil delivery mechanisms from units designed to combust fuel oil and CTRTs is not an indication that the material is being “discarded” and is thus a solid waste.
In general, industry argues that any combustor that purchases CTRTs for use as a fuel is purchasing the material because of its fuel value and that any burning is clearly for generating energy, as opposed to discarding CTRTs. Otherwise, they argue it would lead to the absurd result that for a boiler that can burn fuel oil and CTRTs, the CTRTs would be considered a non-waste fuel, whereas another boiler that cannot burn fuel oil, but also burns CTRTs, the CTRTs would be considered a solid waste. Some recyclers and combustors, according to industry, have been managing CTRTs as non-waste fuel, irrespective of the type of boiler or combustion unit.
While we agree with industry that the agency may list an NHSM categorically by balancing the legitimacy criteria against other relevant factors (40 CFR 241.4(b)(5)(ii)), we do not agree that the Agency can simply ignore any of the legitimacy criteria, particularly the contaminant legitimacy criterion. In particular, industry argues that any biomass material regardless of the contaminant or how contaminated it is, should be considered a non-waste fuel.
Purchase of the material as a commodity for its fuel value is a factor, but not determinative when considering whether discard has occurred. Further, elevated levels of contaminants remaining in the material can indicate that the material is being discarded. While the Agency recognizes that other relevant factors may be considered when one of the legitimacy criteria are not met, there is a limit to the levels of contamination allowed in balancing other relevant factors with the legitimacy criteria to determine whether discard occurs.
We do not agree with petitioner's claim that CTRTs are functionally the same as other comparable traditional fuels, such as fossil fuels that are used in a fuel mix to maintain an appropriate Btu level for the biomass boilers and are combusted in the same units and subject to the same air pollution controls. CTRT contains contaminants at levels that are not comparable to the contaminant levels in biomass, the traditional fuel the units' combusting CTRT are designed to burn. As discussed, there is a limit to the levels of such contamination allowed in balancing other relevant factors, and elevated levels of contaminants remaining in the material can show that the material is being discarded. Further, all CTRTs are not functionally the same as comparable
We also do not agree that CTRTs are integral to the production process. In a previous categorical determination for resinated wood, the Agency did conclude that the material was integrated into the production process and was thus a categorical non-waste (78 FR 9155, February 7, 2013). The Agency based that conclusion on information indicating that resinated wood production facilities were specifically designed to utilize that material for their fuel value, and the plants could not operate as designed without the use of resinated wood. Similar information was not received for CTRTs.
We do agree with industry to a certain extent that removal of oil delivery mechanisms from units designed to combust fuel oil and CTRTs does not support a conclusive decision that the CTRTs are now being “discarded.” While contamination levels may be higher when compared to natural gas, these particular facilities have demonstrated the ability to combust fuel oil along with CTRTs and should not be penalized for switching to a cleaner fuel. As discussed in section V.C.3. of this preamble, the information from industry stated that while stoker, bubbling bed or fluidized bed boilers at major source
The proposed rule, as noted above, outlined the additional approach the Agency considered that would include as a categorical non-waste, CTRTs that are combusted in existing units at major source pulp and paper mills that have been modified in order to use clean fuel such as natural gas, instead of fuel oil. The additional approach required that such CTRTs only be combusted if certain conditions were met (in addition to the requirement that the CTRTs had been processed) that were intended to ensure that the CTRTs are not being discarded. Those conditions included in the proposal are: The CTRTs must be combusted in an existing stoker, bubbling bed or fluidized bed boiler; the CTRTs can comprise no more than 40 percent of the fuel used on a monthly basis; the boiler that burned the CTRTs must have been designed to burn both fuel oil and biomass; and the boiler is modifying its design to burn natural gas.
The Agency stated that the approach was meant to address only the circumstance where fuel oil and biomass facilities were modified in order to combust natural gas as a fuel for normal operations. The facilities in this case would have been met the legitimacy criteria if they did not switch to the cleaner natural gas fuel. The EPA now adopts as a final determination the reasoning in the proposal that it is appropriate for the Agency to decide that the switching to the cleaner natural gas
As noted above, the Agency is adopting the additional approach with some revisions. Specifically, based on comments received and information in the rulemaking record, the Agency has sufficient information to list as categorical non-wastes CTRTs that are processed and combusted in units at major pulp and paper mills or units at power production facilities subject to 40 CFR 63 Subpart DDDDD (Boiler MACT) that combust CTRT and had been designed to burn biomass and fuel oil, but are modified (
• CTRTs must be combusted in existing (
• CTRTs can comprise no more than 40 percent of the fuel that is used on an annual heat input basis.
The standard is applicable to existing CTRT units burning CTRTs that had been designed to burn fuel oil and biomass and have been modified to burn natural gas. The standard will also apply if an existing CTRT unit designed to burn fuel oil and biomass is modified at some point in the future.
The additional approach adopted for the final rule addresses only the circumstance where contaminants in CTRTs are comparable to or less than the traditional fuels the unit was originally designed to burn (both fuel oil and biomass) but that design was modified in order to combust natural gas. The approach is not a general means to circumvent the contaminant legitimacy criterion by allowing combustion of any NHSM with elevated contaminant levels,
Based on comments received on the proposed rule, several revisions were made in the additional approach for the final rule under section 241.7(a): (1) CTRTs combusted in units at power producers subject to 40 CFR part 63 Subpart DDDDD (Boiler MACT) were added to the categorical listing; (2) the 40% fuel load limit was changed to an annual heat input basis; regulatory
See section V.C.6. Response to Comments for a further discussion of the changes identified above. The Agency has also determined that recordkeeping requirements under the Boiler MACT 40 CFR part 63 at section 63.7555(d)(2) are sufficient to document compliance with these standards. See section V.C.6. for a further discussion of recordkeeping requirements.
The proposed rule identified several issues pertaining to the listing of CTRTs as categorical non-wastes and requested comment on those issues which are summarized below (see also section V.C.6 of this preamble):
The EPA should also include units that have already switched from fuel oil to natural gas or are currently being modified to switch from fuel oil to natural gas, in addition to those that will switch from fuel oil to natural gas in the future. Many pulp and paper mills formerly combusted fuel oil, but have already moved or are moving away from fuel oil to natural gas. The EPA's rationale applies equally in each case.
Moreover, if the EPA retains the limitation on the types of boilers at pulp and paper mills that can combust CTRTs under the expanded listing, hybrid suspension grate boilers should be added to that list because they are similar to the listed boilers and combust CTRTs, as well as other biomass fuels.
Thus, combustion of CTRTs in boiler units in the sectors identified above that are designed to burn both biomass and fuel oil but have been modified to burn biomass and natural gas should not be considered discard. The additional approach is meant to address only the circumstance where contaminants in CTRTs are comparable to or less than the traditional fuels the unit was designed to burn (both fuel oil and biomass) but that design has been modified in order to combust natural gas. The approach is not a general means to circumvent the contaminant legitimacy criterion by allowing combustion of any NHSM with elevated contaminant levels,
Based on information from industry that in addition to stoker, bubbling bed and fluidized bed boilers, hybrid suspension grate (HSG) boilers also combust CTRT,
On November 5th, 2015, EPA signed a final reconsideration for the Boiler MACT. In that action, the definition of the HSG subcategory was modified to require demonstration of the 40 percent moisture level (as-fired basis) using monthly fuel analysis, instead of a 40 percent moisture level on an annual average heat input basis. The addition of the monthly requirement will require consistently high moisture contents of the fuels fired in HSG boilers thus limiting the use of the drier CTRT.
We have also determined that the annual heat input basis is the appropriate measure for facilities to use instead of the proposed monthly basis. Several commenters stated that facilities already measure and keep records on an annual basis, and we have noted that the subcategory applicability records required by the major source boiler NESHAP are on an annual heat input basis as well. Thus this approach maintains consistency with other recordkeeping requirements required under other rules and practices already in place.
This non-waste determination approach is also extended to CTRTs combusted in units at power production facilities subject to 40 CFR part 63 Subpart DDDDD (Boiler MACT) in addition to major source pulp and paper mills. The information sources cited above indicate that these types of units may combust both CTRTs and fuel oil. The sources did not show that chemical manufacturing facilities combust both types of fuels, thus these facilities were not included in the categorical non-waste determination for units that have been modified to burn biomass and natural gas instead of biomass and fuel oil.
Other commenters supported such recordkeeping requirements, explaining that the EPA and/or delegated state or local air agencies will have no way to ensure compliance with the conditions without requiring recordkeeping. If required, recordkeeping should be streamlined with air quality requirements, in other words, one system may support the NHSM determination and air pollution control requirements.
It is environmentally preferable to avoid the use of coal or fuel oil for that higher Btu fuel, and the EPA shouldn't discourage facilities from switching to biomass by not allowing the co-firing of CTRTs. The EPA can balance other factors against the contaminant legitimacy criterion, and the environmental benefits of coal-to-biomass conversion are a relevant factor to be considered.
Many biomass boilers in the forest products industry rely on CTRT fuel but are not current or former users of either oil or coal. CTRT is a significant fuel for a number of biomass plants and will become increasingly important as facilities are forced to secure feedstocks from non-forest product sources.
The biomass power industry operates with mostly grid-connected standalone power plants which use organic materials in the production of energy. These commenters reported that 20-35 percent of the organic materials used in these facilities are CTRTs, stressing that CTRTs enhance boiler performance and efficiency, and are therefore valuable to these facilities because of their high BTU value, low moisture content, and low ash.
Biomass power facilities may also be subject to Renewable Portfolio Standards which provide states with a mechanism to increase renewable energy generation. Such programs require energy utilities to supply a minimum amount of customer load from eligible renewable energy sources, such as biomass rather than fossil fuel sources such as fuel oil.
The key for the facilities discussed in the comment is the use of both fuel oil and biomass as fuels that the facilities are designed to burn. Since the comment discusses facilities that do not use fuel oil in their fuel mix now or in the past, they do not meet legitimacy criteria for contaminant comparison and will not be eligible for the categorical listing regarding CTRTs. Under these conditions, the CTRTs have been discarded when they are burned as a fuel.
The “designed to burn” condition was intended to determine which traditional fuels should be the basis of comparison for the contaminant levels in the material under evaluation as a non‐waste fuel, not to put limitations on the use of the NHSM as non‐waste fuel. As the EPA stated “the reason we analyze what a unit is designed to burn is to decide the traditional fuel(s) to which contaminants should be compared. This comparison is then used as an aid to decide whether the NHSM is being legitimately used as a fuel or whether excess contaminants show that the burning is waste treatment” (78 FR 9149).
As further discussed in section V.C.4. of this preamble, for CTRTs, the Agency considered traditional fuel contaminant comparison information for biomass, fuel oil and coal. To meet the contaminant legitimacy criterion, the Agency determined that CTRTs must be combusted in units designed to burn biomass and fuel oil due to elevated levels of SVOCs, or as described, above in specific industry facilities that have switched from burning fuel oil and biomass to natural gas and fuel oil. Units designed to burn both biomass and fuel oil may, in addition, burn coal or other traditional fuels if the unit is also designed to burn that material. With respect to the comment's view of the TDF categorical listing, the EPA first notes that that listing has not been reopened for any comment. Regardless, the EPA disagrees with the comment that there is no designed to burn provision in the categorical listing. Any categorical listing imposes a requirement that legitimacy criteria must be met, as is the case for any material burned as a fuel in order to be burned as a product fuel. Facilities that are not designed to burn coal may not burn TDF because they will be burning a “dirtier” fuel than would normally be burned by the facility. While a separate case-by-case determination regarding contaminants does not have to be made, TDF may not be burned in an oil or gas-fired facility under CAA section 112. In such a case there would be substantial burning of waste contaminants, which would result in the application of CAA section 129 standards.
The categorical listing for tires was based on the determination made in the March 21, 2011 rule (76 FR 15456) that TDF had contaminants at levels comparable to or less than coal, the traditional fuel which TDF would replace.
CTRTs should be allowed to be used as a fuel in units designed, built and operated to burn biomass, provided that the units are operated in compliance with their air permit regardless of their capacity to burn fuel oil. These units are designed to burn solid fuels, and CTRTs are a solid fuel. Requiring boilers to be equipped with fuel oil delivery systems would result in unnecessary permitting and burden with no environmental benefit. The commenter further notes that the EPA's concerns on combustion by-products and PAH are best addressed through air permitting.
The Agency also disagrees that because the units are operated in compliance with the air permits, the units should be allowed to burn CTRTs regardless of the capacity to burn fuel oil. The determination whether CTRTs are a waste or a non-waste and, thus, whether CTRTs can be combusted in a particular unit is made prior to combustion of the material. Emission standards, either CAA section 112 or CAA section 129, are applied through the permit based on the waste-non-waste determination. The concept of the NHSM rule is to determine whether particular materials should be burned as waste fuels or product fuels, while the air permit emission standards help ensure protection of human health and the environment for burning of the NHSM in the unit.
When balanced against the contaminant legitimacy criterion it should outweigh any implication the EPA is inferring from the PAH levels that discard is occurring. CTRTs may have higher concentrations of such semi-volatile organic compounds in comparison to biomass, but the EPA should give more weight to other factors demonstrating that CTRTs are fuel rather than waste (such as the long‐standing practice of purchasing CTRTs as a viable fuel source for boilers).
EPA also stated in the December 2011 preamble (76 FR 80471) that “certain NHSMs may not meet the legitimacy criteria, especially the `contaminant legitimacy criterion,' in all instances, but the material would still generally be considered a non-waste fuel.” It is appropriate to balance the legitimacy criteria and other relevant factors in determining that a NHSM is not a solid waste when used as a fuel in a combustion unit. The motivation of the combustor is a significant factor that should be considered in a non-waste determination. CTRTs are generally purchased under contracts to provide a reliable, cost-effective fuel source, rather than burned to destroy a group of contaminants. Use of CTRTs are important in reducing carbon dioxide emissions, maintaining capacity for managing agricultural biomass and urban wood, and the continued economic viability of many facilities as relevant factors for the EPA to balance with the contaminant legitimacy criterion.
Further, the EPA disagrees that elevated PAH levels should not compel the conclusion that CTRTs can only be combusted as product fuels in units designed to burn fuel oil or in existing units that had combusted fuel oil in the past and switched to a cleaner natural gas fuel. As discussed in the February 7, 2013 final rule and the proposed rule (79 FR 21027), the Agency can list an NHSM categorically by balancing the legitimacy criteria against other relevant factors (40 CFR 241.4(b)(5)(ii)) as is done for CTRTs combusted in existing units that had switched to natural gas. However, balancing does not mean the Agency can simply ignore any of the legitimacy criteria no matter the type of levels or contaminants because the material is a source of fuel with higher Btu value and low moisture. In the case of CTRTs, to the extent that a combustion unit was never designed to burn fuel oil and biomass, the traditional fuels that are most comparable to CTRTs, the Agency would be allowing toxic contaminants that are present in the CTRTs several orders of magnitude higher than what is found in the traditional fuel. While the Agency recognizes that other relevant factors, including purchase of the material as a commodity for its fuel value, may be considered when one of the legitimacy criteria are not met, we do not agree that consideration of such factors would allow the EPA to undermine the legitimacy criterion if it is inconsistent with the concept of discard.
By adopting the approach suggested by the commenters, the Agency would be allowing any biomass-based material that is significantly contaminated to be burned in any combustion unit, including residential and commercial boilers. We also do not agree with petitioner's claim that CTRTs are functionally the same as other
The Agency agrees that more clarity is needed regarding combustion of CTRTs in units designed to burn coal in addition to biomass and fuel oil (information was not received by the Agency regarding coke). Footnote 96 in the proposal, cited by the commenter, stated that units designed to burn both biomass and fuel oil may, in addition, burn coal if the unit is also designed to burn that material and still be eligible for the categorical non-waste determination. Cement kilns are an example of a combustor that may have the ability to combust all fuels (see also discussion on cement kilns in C&D wood in section V.A.5. of this preamble).
To provide additional clarity regarding units designed to burn coal, fuel oil and CTRTs, the footnote was deleted, and an expanded explanation was provided in section V.C.4. of this preamble stating that the EPA considered two scenarios for units that combust CTRTs, fuel oil and coal. For purposes of contaminant comparison to that traditional fuel, the EPA considered two scenarios.
In the first scenario, where CTRTs were combusted in units designed to burn only coal and biomass, contaminant levels in CTRTs were compared to those two traditional fuels.
In the second scenario, a combustion unit is designed to burn coal, biomass and fuel oil. SVOCs are present in CTRTs (up to 22,883 ppm) at levels well exceeding those in coal and biomass but within the range observed in fuel oil (up to 54,700 ppm). As previously mentioned, fluorine, and nitrogen levels in CTRTs are present at elevated levels when compared to fuel oil. However, the highest levels of fluorine (100 ppm) and nitrogen (14,400 ppm) are comparable to, or well within, the levels of these contaminants in biomass. All other contaminants in CTRTs are comparable to those in coal. Thus, CTRTs can be combusted in units burning coal, but only if the unit is also designed to burn fuel oil and biomass. CTRTs have comparable contaminant levels in units designed to burn biomass, fuel oil and coal, and as such, meet this legitimacy criterion if used in facilities that are designed to burn those traditional fuels.
In addition to units combusting biomass, fuel oil and coal, consistent with the discussion above, CTRTs also can be combusted in units at major pulp and paper mills and in units at power production facilities subject to the Boiler MACT that had been designed to burn biomass, fuel oil and coal but were modified (
The EPA's use of “can be” is inconsistent with the language in the preamble: “We would like to make clear that the Agency would consider units to meet this requirement if the unit combusts fuel oil as part of the normal operations and not solely as part of start-up or shut down operations.” The EPA should restate this sentence as “We would like to make clear that the Agency would consider units to meet this requirement if the unit can combust fuel oil as part of the normal operations which includes periods of start-up or shut down operations.”
The EPA has already reviewed data that demonstrates that the levels of contaminants in borate-treated wood are comparable to those found in unadulterated wood. The December, 2013, data submitted to the EPA by the Treated Wood Council,
Because the EPA has already established that CTRTs meet the other two legitimacy criteria (managed as a valuable commodity and having meaningful heat value), all three legitimacy criteria are met for borate-treated wood. As such, ties treated with a combination of creosote and borate also meet the criteria and should be included in this rulemaking.
Various consequences may arise if the EPA fails to include dual-treated ties in the non-waste listing. First, the utility of the CTRT non-waste listing would be short-lived, as most newer ties are treated with borate as well as creosote. Secondly, because borate is typically applied first and then covered with creosote treatment, suppliers will struggle to distinguish between the two types of ties. Although these newer ties are likely to be in service currently, when they need to be replaced they would likely be processed with creosote-only-treated ties, this would create uncertainty regarding the waste status of all railroad ties, and the CTRT processing industry would be adversely affected.
Some CTRT business partners are evaluating investments in new CTRT processing facilities that are located closer to the facilities that combust them, in order to address transportation costs, but these partners would have stranded assets when dual-treated ties begin to be removed from service, and the uncertainty would prevent investments from being made.
Several consequences of not including dual-treated ties in this categorical determination are identified. The first suggested consequence stated that most newer ties are treated with borate and the utility of a creosote only categorical listing would be short-lived. As indicated, this final rule determination on dual-treated ties is based on a single data point, however, the EPA could revisit that determination in the future should additional data be made available. Further, not including dual-treated ties in this rule's CTRT categorical determination does not necessarily preclude suppliers from determining that dual-treated ties are non-wastes. Instead of relying on this rule's categorical non-waste determination, the suppliers can instead follow the procedures outlined in 40 CFR 241.3 to make a non-waste determination specific to their product.
The commenter also suggests that suppliers and CTRT processing facilities may have difficulty in distinguishing between CTRTs and dual-treated ties. These statements, however, are inconsistent with information received by the Agency on management of CTRTs. As stated in section V.C.1. of this preamble, contracts for the purchase and combustion of CTRTs may include fuel specifications limiting contaminants, such as metal, and precluding the receipt of wood treated with preservatives other than creosote.
Ties that are not processed into a new product fuel that meets legitimacy criteria would be considered discarded, but the rule did not specifically identify how the ties should be processed. As discussed in section V.C.4. of this preamble, certain practices are standard within the industry for the processing of cross-ties into fuel by reclamation/processing companies. Specifically, metals (spikes, nails, plates, etc.) are removed using a magnet which may occur several times during the process. The cross-ties are then ground or shredded to a specified size depending on the particular needs of the end-use combustor.
To provide specificity as to how CTRTs must be processed to meet the requirements of the categorical non-waste standard, the language pertaining to CTRTs as a categorical non-waste fuel under 40 CFR 241.4 is amended as follows: “Creosote-treated railroad ties that are processed and then combusted in units designed to burn both biomass and fuel oil as part of normal operations and not solely as part of start-up or shut-down operations. Processing must include, at a minimum, metal removal and shredding or grinding.
The Agency received a petition from the Treated Wood Council in April 2013 requesting that nonhazardous treated wood (including borate and copper naphtenate) be categorically listed as non-waste fuels in 40 CFR 241.4(a). Under the April 2013 petition, nonhazardous treated wood would include waterborne borate based preservatives, waterborne organic based preservatives, waterborne copper based wood preservatives (ammoniacal/alkaline copper quat, copper azole, copper HDO, alkaline copper betaine, or copper naphthenate); creosote; oilborne copper naphthenate; pentachlorophenol; or dual-treated with any of the above. In the course of EPA's review of the petition, additional data was requested and received, and meetings were held between TWC and EPA representatives.
In an August 21, 2015 letter from TWC to Barnes Johnson,
The Agency has reviewed TWC information on the three treated railroad ties, creosote borate, copper naphtenate, and copper naphtenate-borate, submitted on September 11, 2015 and has requested additional contaminant data which was submitted on October 5, 2015 and October 19, 2015. Based on information provided to the Agency to date, we believe these three treated railroad ties are candidates for categorical non-waste listings and expect to begin development of a proposed rule under 40 CFR 241.4(a) regarding those listings in the near future.
The Agency understands the importance of the January 31, 2016 compliance deadline for existing boiler units and the need to make decisions on fuel use by that deadline. Agency action on the three treated railroad ties, however, must follow required action development processes including public notice and comment required under the Administrative Procedures Act. Due to such processes, the categorical non-waste listing could not be completed prior to the January deadline. The Agency emphasizes, however, that facilities may also make self-determinations of their material under 40 CFR 241.3(b). In order to be regulated under CAA section 112 rather than CAA section 129, a combustion source can make a non-waste determination for the NHSM used as fuel when managed within their control (241.3(b)(1)); or for fuel or products produced from processed discarded NHSM (241.3(b)(4)). Prior to the effective date of this rule, such self-determinations may apply to materials categorically listed as non-wastes by this rule.
In an October 5, 2015 meeting with the Office of Management and Budget under EO 12866, industry representatives indicated that although the three types of RR ties are just coming into use, a few may have to be replaced, collected and mixed in with cresosote treated railroad ties by processor prior to being sent to the combustor. Industry representatives were concerned that the presence of these small amounts of creosote borate, copper naphtenate, and copper naphtenate-borate, since they are not included in the categorical determination, would render all of the creosote treated processed ties into solid wastes. The Agency has determined that small (de minimis) amounts of such materials would not result in determinations that the creosote ties being combusted are solid wastes. This is supported by the rulemaking record, specifically the discussion in the March 2011 final rule where commenters argued that there should be a
NHSMs that are not solid wastes when combusted are identified under 40 CFR 241.3(b). Paragraphs (i) and (ii) of 40 CFR 241.3(b)(2) were reserved in response to the 40 CFR 241.4(a)(1) categorical non-waste standards in the February 7, 2013 rulemaking. Those standards had eliminated the need for previous standards under 40 CFR 241.3(b)(2)(i) and (ii) related to scrap tires managed under established tire collection programs and resinated wood (see section IV.A. History of NHSM Rulemakings). However, reserving only 40 CFR 241.3(b)(2)(i) and (ii), and not the introductory sentence, led to some confusion with the categorical non-waste standards. For clarity, and to ensure consistent numbering with the following sections, we proposed to amend 40 CFR 241.3(b)(2) by reserving paragraph (b)(2) in its entirety.
The description of the petition process identified in 40 CFR 241.3(c)(1) contains a typographical error. Specifically, the last sentence of the 40 CFR 241.3(c)(1) regulatory text from the February 2013 final rule is stated as
However, the intent of this sentence is to say that the determination is based on “whether it has or has not been discarded” in addition to other factors. Therefore, we proposed to amend the regulatory text to add a “not” before “been discarded” and remove “that” after “non-hazardous secondary material.” The proposed regulatory text, therefore, was “. . . The determination will be based on whether the non-hazardous secondary material has not been discarded is a legitimate fuel as specified in paragraph (d)(1) of this section and on the following criteria:”
A comment was received on the proposed amendments stating the word “that” appears to have been omitted in the last sentence, and should be add to the sentence as shown in italics below:
“The determination will be based on whether the non-hazardous secondary material
The Agency agrees with the commenter. The word “that” clarifies the sentence's meaning and should not have been omitted. Thus, the sentence in the final rule reads: “The determination will be based on whether the non-hazardous secondary material
The Agency also proposed to make a technical correction to 40 CFR 241.3(d)(1)(iii) to clarify that the provision applies to cement kilns, as well as boilers. Specifically, that section of the rule identifies the legitimacy criteria for NHSMs relating to contaminant comparisons between the traditional fuel(s) a unit is designed to burn and the NHSM. It states that a person may choose a traditional fuel that can be burned in any type of
Beyond expanding the list of NHSMs that categorically qualify as non-waste fuels, this rule does not change the effect of the NHSM regulations on other programs as described in the March 21, 2011 NHSM final rule, as amended on February 7, 2013 (78 FR 9138). Refer to section VIII of the preamble to the March 21, 2011 NHSM final rule
This final rule does not change the relationship to state programs as described in the March 21, 2011 NHSM final rule. Refer to section IX of the preamble to the March 21, 2011 NHSM final rule
No federal approval procedures for state adoption of this final rule are included in this rulemaking action under RCRA subtitle D. Although the EPA does promulgate criteria for solid waste landfills and approves state municipal solid waste landfill permitting programs, RCRA does not provide the EPA with authority to approve state programs beyond those landfill permitting programs. While states are not required to adopt regulations promulgated under RCRA subtitle D, some states incorporate federal regulations by reference or have specific state statutory requirements that their state program can be no more stringent than the federal regulations. In those cases, the EPA anticipates that, if required by state law, the changes being proposed in this document, if finalized, will be incorporated (or possibly adopted by authorized state air programs) consistent with the state's laws and administrative procedures.
The value of any regulatory action is traditionally measured by the net change in social welfare that it generates. This rulemaking establishes a categorical non-waste listing for selected NHSMs under RCRA. This categorical non-waste determination allows these materials to be combusted as a product fuel in units, subject to the section 112 CAA emission standards, without being subject to a detailed case-by-case analysis of the material(s) by individual combustion facilities, provided they meet the conditions of the categorical listing. The rule establishes no direct standards or requirements relative to how these materials are managed or combusted. As a result, this action alone does not directly invoke any costs
Because this RCRA action is definitional only, any costs or benefits indirectly associated with this action would not occur without the corresponding implementation of the relevant CAA rules. However, in an effort to ensure rulemaking transparency, the EPA prepared an assessment in support of this action that examines the scope and direction of these indirect impacts, for both costs and benefits.
This action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review, because it may raise novel legal or policy issues [3(f)(4)] arising out of legal mandates, although it is not economically significant. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an economic analysis of the potential costs and benefits associated with this action. This analysis, “Assessment of the Potential Costs, Benefits, and Other Impacts for the Final Rule—Categorical Non-Waste Determination for Selected Non-Hazardous Secondary Materials (NHSMs): Construction and Demolition Wood, Recycling Process Residuals, and Creosote-Treated Railroad Ties”, is available in the docket. Interested persons are encouraged to read and comment on this document.
The information collection activities in this rule will be submitted for approval to the Office of Management and Budget (OMB) under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number 2493.03. 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.
This action will impose a direct RCRA related burden associated with reading and understanding the rule. This burden is estimated at approximately $102 per entity and would impact facilities that generate the NHSMs, and those that combust these materials as a fuel product. Combustors of C&D wood must also request a written certification from C&D processing facilities that the C&D wood that they intend to burn as a non-waste fuel has been processed by trained operators in accordance with best management practices, as defined in the rule. The preparation of the certification statement and the need to maintain certification status is the responsibility of the processor. The combustors also would be required to maintain the certification statement on file; however, there is already an existing requirement for combustors to maintain records that show how they are in compliance with the 40 CFR 241.3 and 241.4 requirements (40 CFR 60.2740(u) (Emissions Guidelines) and 40 CFR 60.2175(w) (New Source Performance Standards) for CISWI units and 40 CFR 63.11225(c)(2)(ii) for area source boilers and 40 CFR 63.7555(d)(2) for major source boilers). Because there are already existing recordkeeping requirements for combustors to maintain records that show how they are in compliance with the 40 CFR 241.3 and 241.4 requirements, the requirement to maintain the certification statement provided by the processor would simply be in place of records that would need to be maintained for processed C&D wood, absent a categorical non-waste fuel determination. OMB has previously approved the information collection requirements contained in the existing NHSM regulation at 40 CFR part 241 under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information 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. When OMB approves this ICR, the Agency will announce that approval in the
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule. The addition of the three NHSMs to the list of categorical non-waste fuels will indirectly reduce materials management costs. In addition, this action will reduce regulatory uncertainty associated with these materials and help increase management efficiency. We have therefore concluded that this final rule will relieve regulatory burden for all affected small entities. We continue to be interested in the potential impacts of the final rule on small entities and welcome comments on issues related to such impacts outside the scope of this rule.
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 imposes no enforceable duty on any state, local or tribal governments or the private sector.
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 has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law. Potential aspects associated with the categorical non-waste fuel determinations under this final rule may invoke minor indirect implications to the extent that entities generating or consolidating these NHSMs on tribal lands could be affected. However, any impacts are expected to be negligible.
The proposed rule solicited comment from tribal officials on actions contained in the rule. As no comments were received, the above determination is adopted for this final rule.
This action is not subject to Executive Order 13045 because it is not economically significant as defined in Executive Order 12866, and because the
The final rule may indirectly stimulate the increased fuel use of one or more of the three NHSMs by providing enhanced regulatory clarity and certainty. This increased fuel use may result in the diversion of a certain quantity of these NHSMs away from current baseline management practices. Any corresponding disproportionate impacts among children would depend upon: (1) Any potential change in emissions from combustion units subject to the CAA section 112 standards, relative to baseline management patterns, and (2) whether children make up a disproportionate share of the population near the affected combustion units. Therefore, to assess the potential for the final rule to result in an indirect disproportionate effect on children, we conducted a demographic analysis for this population group surrounding CAA section 112 major source boilers, municipal solid waste landfills, and C&D landfills, and cement kilns.
For major source boilers, our findings indicate that the percentage of the population in these areas under age 18 years of age is generally the same as the national average.
For municipal solid waste and C&D landfills, we do not have demographic results specific to children. However, using the population below the poverty level as a rough surrogate for children, we found that within three miles of facilities that may experience diversions of one or more of these NHSMs, low-income populations, as a percent of the total population, are disproportionately high relative to the national average. Thus, to the extent that these NHSMs are diverted away from municipal solid waste or C&D landfills, any landfill-related emissions, discharges, or other negative activity potentially impacting low-income (children) populations living near these units are likely to be reduced. Finally, transportation emissions associated with the diversion of some of this material away from landfills to boilers are likely to be generally unchanged, while these emissions are likely to be reduced for on-site generators of paper recycling residuals that would reduce off-site shipments.
The public was invited to submit comments or identify peer-reviewed studies and data that assess effects of early life exposure to the specific NHSMs addressed in the proposal. The Agency did not receive comments or studies in these subject areas, and is therefore adopting the determinations described above for this final rule.
This action is not “significant energy action” because it is not likely to have a significance adverse effect on the supply, distribution or use of energy. The selected NHSMs affected by this final action are not generated in quantities sufficient to significantly (adversely or positively) impact the supply, distribution, or use of energy at the national level.
This final rulemaking does not involve technical standards.
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. This is because the overall level of emissions, or the emissions mix from boilers, will not change significantly as the three categorically listed non-waste fuels are comparable to the types of fuels that the combustors would otherwise burn.
Potential indirect impacts on minority and/or low-income citizens have been assessed by looking at the following: (1) Any change in emissions or the emissions mix from combustion units subject to the CAA section 112 standards that may accept increased quantities of one or more of the three NHSMs addressed in this final rule, (2) any change in emissions resulting from the diversion of these NHSMs from their current baseline management methods, and (3) any other impacts related to material diversion (
Our environmental justice assessment
We also considered the potential for non-combustion environmental justice concerns related to the potential incremental increase in NHSMs diversions from current baseline management practices. These include the following:
• Reduced upstream emissions resulting from the reduced production of virgin fuel: Any reduced upstream emissions that may indirectly occur in response to reduced virgin fuel mining or extraction may result in a human health and/or environmental benefit to minority and low-income populations living near these projects.
• Alternative materials transport patterns: Transportation emissions associated with NHSMs diverted from landfills to boilers are likely to be similar, except for on-site paper recycling residuals, where the potential for less off-site transport to landfills may result in reduced truck traffic and emissions where such transport patterns may pass through minority or low-income communities.
• Change in emissions from baseline management units: The diversion of some of these NHSMs away from disposal in landfills may result in a marginal decrease in activity at these facilities. This may include non-adverse impacts, such as marginally reduced emissions, odors, groundwater and surface water impacts, noise pollution, and reduced maintenance cost to local infrastructure. Because municipal solid waste and C&D landfills were found to be located in areas where minority and low-income populations are disproportionately high relative to the national average, any reduction in activity and emissions around these facilities is likely to benefit the citizens living near these facilities.
Finally, this rule, in conjunction with the corresponding CAA rules, may help accelerate the abatement of any existing stockpiles of the targeted NHSMs. To the extent that these stockpiles may represent negative human health or environmental implications, minority and/or low-income populations that live near such stockpiles may experience marginal health or environmental improvements. Aesthetics may also be improved in such areas.
As previously discussed, this RCRA action alone does not directly require any change in the management of these materials. Thus, any potential materials management changes stimulated by this action, and corresponding impacts to minority and low-income communities, are considered to be indirect impacts, and would only occur in conjunction with the corresponding CAA rules.
This action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a “major rule” as defined by 5 U.S.C. 804(2).
Environmental protection, Air pollution control, Waste treatment and disposal.
For the reasons stated in the preamble, Title 40, chapter I, of the Code of Federal Regulations is amended as follows:
42 U.S.C. 6903, 6912, 7429.
(c) * * *
(1) Submittal of an application to the Regional Administrator for the EPA Region where the facility or facilities are located or the Assistant Administrator for the Office of Land and Emergency Management for a determination that the non-hazardous secondary material, even though it has been transferred to a third party, has not been discarded and is indistinguishable in all relevant aspects from a fuel product. The determination will be based on whether the non-hazardous secondary material that has not been discarded is a legitimate fuel as specified in paragraph (d)(1) of this section and on the following criteria:
(d) * * *
(1) * * *
(iii) The non-hazardous secondary material must contain contaminants or groups of contaminants at levels comparable in concentration to or lower than those in traditional fuel(s) that the combustion unit is designed to burn. In determining which traditional fuel(s) a unit is designed to burn, persons may choose a traditional fuel that can be or is burned in the particular type of combustion unit, whether or not the unit is permitted to burn that traditional fuel. In comparing contaminants between traditional fuel(s) and a non-hazardous secondary material, persons can use data for traditional fuel contaminant levels compiled from national surveys, as well as contaminant level data from the specific traditional fuel being replaced. To account for natural variability in contaminant levels, persons can use the full range of traditional fuel contaminant levels, provided such comparisons also consider variability in non-hazardous secondary material contaminant levels. Such comparisons are to be based on a
(a) * * *
(5) Construction and demolition (C&D) wood processed from C&D debris according to best management practices. Combustors of C&D wood must obtain a written certification from C&D processing facilities that the C&D wood has been processed by trained operators in accordance with best management practices. Best management practices for purposes of this categorical listing must include sorting by trained operators that excludes or removes the following materials from the final product fuel: non-wood materials (
(i)
(A) Exclude all painted wood (to the extent that only de minimis quantities inherent to processing limitations may remain) from the final product fuel,
(B) Use X-ray Fluorescence to ensure that painted wood included in the final product fuel does not contain lead-based paint, or
(C) Require documentation that a building has been tested for and does not include lead-based paint before accepting demolition debris from that building.
(ii)
(A) Remove all painted wood (to the extent that only de minimis quantities inherent to processing limitations may remain),
(B) Use X-ray Fluorescence to detect and remove lead-painted wood, or
(C) Require documentation that a building has been tested for and does not include lead-based paint before accepting demolition debris from that building.
(iii)
(iv)
(6) Paper recycling residuals generated from the recycling of recovered paper, paperboard and corrugated containers and combusted by paper recycling mills whose boilers are designed to burn solid fuel.
(7) Creosote-treated railroad ties that are processed and then combusted in the following types of units. Processing must include, at a minimum, metal removal and shredding or grinding.
(i) Units designed to burn both biomass and fuel oil as part of normal operations and not solely as part of start-up or shut-down operations, and
(ii) Units at major source pulp and paper mills or power producers subject to 40 CFR part 63, subpart DDDDD, that combust CTRTs and had been designed to burn biomass and fuel oil, but are modified (
(A) CTRTs must be burned in existing (
(B) CTRTs can comprise no more than 40 percent of the fuel that is used on an annual heat input basis.
Category | Regulatory Information | |
Collection | Federal Register | |
sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
Publisher | Office of the Federal Register, National Archives and Records Administration |