Federal Register Vol. 81, No.25,

Federal Register Volume 81, Issue 25 (February 8, 2016)

Page Range6411-6743
FR Document

Current View
Page and SubjectPDF
81 FR 6562 - Sunshine Act MeetingPDF
81 FR 6430 - Elimination of Nonimmigrant Visa Exemption for Certain Caribbean Residents Coming to the United States as H-2A Agricultural WorkersPDF
81 FR 6571 - 60-Day Notice of Proposed Information Collection: Overseas Schools Grant Status ReportPDF
81 FR 6501 - Secretary's Advisory Committee on Animal Health; MeetingPDF
81 FR 6477 - Oklahoma Regulatory ProgramPDF
81 FR 6504 - Information Collection Activity; Comment RequestPDF
81 FR 6479 - Virginia Regulatory ProgramPDF
81 FR 6518 - Commission To Eliminate Child Abuse and Neglect Fatalities; Announcement of MeetingsPDF
81 FR 6518 - Submission for OMB Review; Permits, Authorities, or FranchisesPDF
81 FR 6516 - Information Collection; Use of Project Labor Agreements for Federal Construction ProjectsPDF
81 FR 6537 - North Cumberland Wildlife Management Area, Tennessee Lands Unsuitable for Mining Draft Petition Evaluation Document and Environmental Impact Statement-OSM-EIS-37PDF
81 FR 6519 - Submission for OMB Review; Evaluation of Export OffersPDF
81 FR 6524 - Office of Foods and Veterinary Medicine; Center for Food Safety and Applied Nutrition; Statement of Organization, Functions, and Delegations of AuthorityPDF
81 FR 6503 - Idaho Panhandle Resource Advisory Committee; MeetingPDF
81 FR 6541 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Department of Labor Generic Solution for “Touch-Base” ActivitiesPDF
81 FR 6543 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Self-Employment Training Demonstration EvaluationPDF
81 FR 6542 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Petitions for Modification of Mandatory Safety StandardsPDF
81 FR 6504 - Pure Magnesium From the People's Republic of China: Preliminary Results of Antidumping Duty Administrative Review; 2014-2015PDF
81 FR 6542 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Short-Time Compensation GrantsPDF
81 FR 6489 - Trade Monitoring Procedures for Fishery Products; International Trade in Seafood; Permit Requirements for Importers and Exporters; Public MeetingPDF
81 FR 6458 - Notification and Reporting of Aircraft Accidents or Incidents and Overdue Aircraft, and Preservation of Aircraft Wreckage, Mail, Cargo, and RecordsPDF
81 FR 6511 - Receipt of Test Data Under the Toxic Substances Control ActPDF
81 FR 6532 - Agency Information Collection Activities: Collection of Qualitative Feedback Through Focus Groups; Extension, Without Change, of a Currently Approved CollectionPDF
81 FR 6515 - Information Collection; Central Contractor RegistrationPDF
81 FR 6514 - Information Collection; Taxpayer Identification Number InformationPDF
81 FR 6517 - Information Collection; Accident Prevention Plans and RecordkeepingPDF
81 FR 6453 - Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products: Nasal Decongestant Inhaler/Vapor InhalerPDF
81 FR 6451 - Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products: Vicks® VapoInhaler®PDF
81 FR 6526 - Quarterly IRS Interest Rates Used in Calculating Interest on Overdue Accounts and Refunds on Customs DutiesPDF
81 FR 6528 - Agency Information Collection Activities: Country of Origin Marking Requirements for Containers or HoldersPDF
81 FR 6528 - Approval of SGS North America, Inc., as a Commercial GaugerPDF
81 FR 6529 - Approval of SGS North America, Inc., as a Commercial GaugerPDF
81 FR 6525 - Agency Information Collection Activities: Application for Exportation of Articles Under Special BondPDF
81 FR 6506 - Supercalendered Paper From Canada: Initiation of Expedited Review of the Countervailing Duty OrderPDF
81 FR 6488 - Defense Federal Acquisition Regulation Supplement: DFARS Case 2016-D017, Independent Research and Development ExpensesPDF
81 FR 6520 - Proposed Revised Vaccine Information Materials for Hepatitis A and Hepatitis B VaccinesPDF
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 AlaskaPDF
81 FR 6507 - Fisheries of the U.S. Caribbean; Southeast Data, Assessment and Review (SEDAR); U.S. Caribbean Data-Limited SpeciesPDF
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 AreaPDF
81 FR 6533 - 60-Day Notice of Proposed Information Collection: Eligibility of a Nonprofit Corporation/Housing Consultant CertificationPDF
81 FR 6535 - 60-Day Notice of Proposed Information Collection: Validating Estimates of CPD Grantee Accrued ExpensesPDF
81 FR 6508 - Marine Mammals; File No. 18537PDF
81 FR 6509 - Marine Mammals; File Nos. 16193 and 17157PDF
81 FR 6534 - Final Fair Market Rents for the Housing Choice Voucher Program and Moderate Rehabilitation Single Room Occupancy Program Fiscal Year 2016; RevisedPDF
81 FR 6551 - Advisory Committee on the Medical Uses of Isotopes: Meeting NoticePDF
81 FR 6549 - Portland General Electric Company; Trojan Independent Spent Fuel Storage Installation in Columbia County, OregonPDF
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 AmendmentsPDF
81 FR 6597 - Unblocking of Specially Designated Nationals and Blocked Persons Pursuant to the Foreign Narcotics Kingpin Designation ActPDF
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) SurveyPDF
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 FormPDF
81 FR 6514 - Notice of Proposals To Engage in or To Acquire Companies Engaged in Permissible Nonbanking ActivitiesPDF
81 FR 6509 - Technology Advisory Committee Meeting NoticePDF
81 FR 6514 - Formations of, Acquisitions by, and Mergers of Bank Holding CompaniesPDF
81 FR 6514 - Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding CompanyPDF
81 FR 6585 - Notice of Funds Availability Inviting Applications for the Fiscal Year (FY) 2016 Funding Round of the Capital Magnet FundPDF
81 FR 6598 - Sanctions Action Pursuant to Executive Order 13712PDF
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)PDF
81 FR 6578 - Notice of Funding Availability for the Small Business Transportation Resource Center ProgramPDF
81 FR 6576 - Qualification of Drivers; Exemption Applications; VisionPDF
81 FR 6573 - Qualification of Drivers; Exemption Applications; VisionPDF
81 FR 6544 - Notice of Intent To Seek Approval To Establish an Information CollectionPDF
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 13469PDF
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 ProcessPDF
81 FR 6510 - Notice of Availability: CPSC's Draft 2016-2020 Strategic PlanPDF
81 FR 6510 - Agency Information Collection Activities OMB ResponsesPDF
81 FR 6521 - Submission for OMB Review; Comment RequestPDF
81 FR 6531 - Gratuitous Services Agreement and Volunteer Release and Hold HarmlessPDF
81 FR 6530 - Infrastructure Assessments and TrainingPDF
81 FR 6529 - Technical Resource for Incident Prevention (TRIPwire) User RegistrationPDF
81 FR 6568 - Agency Information Collection Activities: Proposed Request and Comment RequestPDF
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 NaturePDF
81 FR 6479 - Prescriptions in Alaska and U.S. Territories and PossessionsPDF
81 FR 6537 - Proposed Appointment to the National Indian Gaming CommissionPDF
81 FR 6523 - Agency Information Collection Activities; Proposed Collection; Comment Request; Extension for a Currently Approved Collection, State Plan for Independent Living (SPIL)PDF
81 FR 6572 - Petition for Exemption; Summary of Petition Received; Wes MyersPDF
81 FR 6572 - Petition for Exemption; Summary of Petition Received; Firestorm UAVPDF
81 FR 6538 - Potassium Permanganate From ChinaPDF
81 FR 6532 - Extension of Agency Information Collection Activity Under OMB Review: Certified Cargo Screening ProgramPDF
81 FR 6551 - Proposed Collection; Comment RequestPDF
81 FR 6565 - Proposed Collection; Comment RequestPDF
81 FR 6554 - Proposed Collection; Comment RequestPDF
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 OptionsPDF
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 301PDF
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 515PDF
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 ProgramPDF
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 FeePDF
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” IndicatorPDF
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 ContractsPDF
81 FR 6512 - Information Collection Being Submitted for Review and Approval to the Office of Management and BudgetPDF
81 FR 6513 - Information Collection Being Reviewed by the Federal Communications CommissionPDF
81 FR 6501 - Notice of Request To Renew an Approved Information Collection; Importation and Transportation of Meat, Poultry, and Egg ProductsPDF
81 FR 6595 - Agency Information Collection Activities: Information Collection Renewal; Comment Request; Privacy of Consumer Financial InformationPDF
81 FR 6512 - Disability Advisory Committee; Announcement of Next MeetingPDF
81 FR 6535 - 60-Day Notice of Proposed Information Collection: Screening and Eviction for Drug Abuse and Other Criminal ActivityPDF
81 FR 6489 - Fisheries of the Exclusive Economic Zone Off Alaska; Western Alaska Community Development Quota ProgramPDF
81 FR 6524 - National Institute on Deafness and Other Communication; Disorders Notice of Closed MeetingPDF
81 FR 6525 - National Institute of Diabetes and Digestive and Kidney Diseases; Notice of Closed MeetingsPDF
81 FR 6525 - National Heart, Lung, And Blood Institute; Notice of Closed MeetingPDF
81 FR 6525 - National Library of Medicine; Amended Notice of MeetingPDF
81 FR 6481 - Approval of California Air Plan Revisions, Department of Pesticide RegulationsPDF
81 FR 6598 - Quarterly Publication of Individuals, Who Have Chosen To Expatriate, as Required by Section 6039GPDF
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 StandardsPDF
81 FR 6522 - Proposed Information Collection Activity; Comment RequestPDF
81 FR 6538 - Notice of Receipt of Complaint; Solicitation of Comments Relating to the Public InterestPDF
81 FR 6613 - Agency Information Collection (Evaluation of the Department of Veterans Affairs Mental Health Services); Activities Under OMB ReviewPDF
81 FR 6508 - Mid-Atlantic Fishery Management Council (MAFMC); Public MeetingPDF
81 FR 6447 - Amendment of Class E Airspace for the Following Michigan Towns: Alpena, MI; and Muskegon, MIPDF
81 FR 6450 - Amendment of Class E Airspace; Wilmington, OHPDF
81 FR 6448 - Amendment of Class E Airspace for the Following Minnesota Towns: Rochester, MN; and St. Cloud, MNPDF
81 FR 6454 - Federal Motor Vehicle Safety Standards; Lamps, Reflective Devices, and Associated EquipmentPDF
81 FR 6411 - Competitive and Noncompetitive Non-Formula Federal Assistance Programs-General Award Administrative Provisions and Specific Administrative ProvisionsPDF
81 FR 6475 - Airworthiness Directives; The Boeing Company AirplanesPDF
81 FR 6434 - Capital Magnet FundPDF
81 FR 6469 - Personnel Management in AgenciesPDF
81 FR 6462 - Financial Assistance Interior RegulationPDF
81 FR 6418 - Single Family Housing Guaranteed Loan ProgramPDF
81 FR 6687 - Additions to List of Categorical Non-Waste FuelsPDF
81 FR 6615 - Waste Prevention, Production Subject to Royalties, and Resource ConservationPDF

Issue

81 25 Monday, February 8, 2016 Contents Agriculture Agriculture Department See

Animal and Plant Health Inspection Service

See

Food Safety and Inspection Service

See

Forest Service

See

National Institute of Food and Agriculture

See

Rural Housing Service

See

Rural Utilities Service

Animal Animal and Plant Health Inspection Service NOTICES Meetings: Secretary's Advisory Committee on Animal Health, 6501 2016-02464 Centers Disease Centers for Disease Control and Prevention NOTICES Vaccine Information Materials for Hepatitis A and Hepatitis B Vaccines; Revisions, 6520-6521 2016-02395 Children Children and Families Administration NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: National Center on Early Head Start-Child Care Partnerships Evaluation, 6521-6522 2016-02351 Procedures for Requests from Tribal Lead Agencies to use Child Care and Development Fund Funds for Construction or Major Renovation of Child Care Facilities, 6522-6523 2016-02297 Same-Sex Relationships: Updates to Healthy Marriage and Relationship Education, 6521 2016-02358 Commerce Commerce Department See

International Trade Administration

See

National Oceanic and Atmospheric Administration

Commodity Futures Commodity Futures Trading Commission NOTICES Meetings: Technology Advisory Committee, 6509-6510 2016-02375 Community Development Community Development Financial Institutions Fund RULES Capital Magnet Fund, 6434-6447 2016-02132 NOTICES Funding Availability: Capital Magnet Fund, 6585-6595 2016-02372 Community Living Administration Community Living Administration NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: State Plan for Independent Living, 6523 2016-02348 Comptroller Comptroller of the Currency NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Privacy of Consumer Financial Information, 6595-6596 2016-02324 Consumer Product Consumer Product Safety Commission NOTICES Draft 2016-2020 Strategic Plan, 6510 2016-02360 Defense Acquisition Defense Acquisition Regulations System PROPOSED RULES Defense Federal Acquisition Regulation Supplements: DFARS Case 2016-D017, Independent Research and Development Expenses, 6488-6489 2016-02396 Defense Department Defense Department See

Defense Acquisition Regulations System

NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Accident Prevention Plans and Recordkeeping, 6517-6518 2016-02406 Central Contractor Registration, 6515-6516 2016-02408 Evaluation of Export Offers, 6519-6520 2016-02448 Permits, Authorities, or Franchises, 6518-6519 2016-02451 Taxpayer Identification Number Information, 6514-6515 2016-02407 Use of Project Labor Agreements for Federal Construction Projects, 6516-6517 2016-02450
Drug Drug Enforcement Administration RULES Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products -- Nasal Decongestant Inhaler/Vapor Inhaler, 6453-6454 2016-02404 Table of Excluded Nonnarcotic Products -- Vicks VapoInhaler, 6451-6453 2016-02403 Environmental Protection Environmental Protection Agency RULES Additions to List of Categorical Non-Waste Fuels, 6688-6743 2016-01866 PROPOSED RULES Air Quality State Implementation Plans; Approvals and Promulgations: California; Department of Pesticide Regulations, 6481-6483 2016-02314 Texas; Infrastructure or Requirements for the 2008 Ozone and 2010 Nitrogen Dioxide National Ambient Air Quality Standards, 6483-6488 2016-02310 NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals, 6510-6511 2016-02359 Test Data under the Toxic Substances Control Act, 6511-6512 2016-02412 Federal Aviation Federal Aviation Administration RULES Amendment of Class E Airspace: Alpena, MI; and Muskegon, MI, 6447-6448 2016-02285 Rochester, MN; and St. Cloud, MN, 6448-6450 2016-02283 Wilmington, OH, 6450-6451 2016-02284 PROPOSED RULES Airworthiness Directives: The Boeing Company Airplanes, 6475-6477 2016-02193 NOTICES Petitions for Exemptions; Summaries: Firestorm UAV, 6572 2016-02345 Wes Myers, 6572-6573 2016-02347 Federal Communications Federal Communications Commission NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals, 6512-6513 2016-02327 2016-02328 Meetings: Disability Advisory Committee, 6512-6513 2016-02323 Federal Motor Federal Motor Carrier Safety Administration NOTICES Qualification of Drivers; Exemption Applications: Vision, 6573-6578 2016-02366 2016-02367 Federal Reserve Federal Reserve System NOTICES Changes in Bank Control: Acquisitions of Shares of a Bank or Bank Holding Company, 6514 2016-02373 Formations of, Acquisitions by, and Mergers of Bank Holding Companies, 6514 2016-02374 Proposals to Engage in or to Acquire Companies Engaged in Permissible Nonbanking Activities, 6514 2016-02376 Fish Fish and Wildlife Service NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: UCAN Survey—National Initiative to Understand and Connect Americans and Nature, 6536-6537 2016-02352 Food and Drug Food and Drug Administration NOTICES Office of Foods and Veterinary Medicine, Center for Food Safety and Applied Nutrition; Statement of Organization, Functions, and Delegations of Authority, 6524 2016-02444 Food Safety Food Safety and Inspection Service NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Importation and Transportation of Meat, Poultry, and Egg Products, 6501-6503 2016-02326 Foreign Assets Foreign Assets Control Office NOTICES Blocking or Unblocking of Persons and Properties, 6596-6598 2016-02364 2016-02371 2016-02379 Forest Forest Service NOTICES Annual List of Newspapers To Be Used By the Alaska Region, etc., 6503 2016-02361 Meetings: Idaho Panhandle Resource Advisory Committee, 6503-6504 2016-02435 General Services General Services Administration NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Accident Prevention Plans and Recordkeeping, 6517-6518 2016-02406 Central Contractor Registration, 6515-6516 2016-02408 Evaluation of Export Offers, 6519-6520 2016-02448 Permits, Authorities, or Franchises, 6518-6519 2016-02451 Taxpayer Identification Number Information, 6514-6515 2016-02407 Use of Project Labor Agreements for Federal Construction Projects, 6516-6517 2016-02450 Meetings: Commission to Eliminate Child Abuse and Neglect Fatalities, 6518 2016-02452 Health and Human Health and Human Services Department See

Centers for Disease Control and Prevention

See

Children and Families Administration

See

Community Living Administration

See

Food and Drug Administration

See

National Institutes of Health

Homeland Homeland Security Department See

Transportation Security Administration

See

U.S. Citizenship and Immigration Services

See

U.S. Customs and Border Protection

NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Gratuitous Services Agreement and Volunteer Release and Hold Harmless, 6531-6532 2016-02356 Infrastructure Assessments and Training, 6530-6531 2016-02355 Technical Resource for Incident Prevention User Registration, 6529-6530 2016-02354
Housing Housing and Urban Development Department NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Eligibility of a Nonprofit Corporation/Housing Consultant Certification, 6533-6534 2016-02389 Screening and Eviction for Drug Abuse and Other Criminal Activity, 6535 2016-02322 Validating Estimates of CPD Grantee Accrued Expenses, 6535-6536 2016-02388 Final Fair Market Rents for the Housing Choice Voucher Program and Moderate Rehabilitation Single Room Occupancy Program Fiscal Year 2016; Revised, 6534-6535 2016-02383 Interior Interior Department See

Fish and Wildlife Service

See

Land Management Bureau

See

Surface Mining Reclamation and Enforcement Office

PROPOSED RULES Financial Assistance Interior Regulation, 6462-6469 2016-02039 NOTICES Proposed Appointment to the National Indian Gaming Commission, 6537 2016-02349
Internal Revenue Internal Revenue Service NOTICES Quarterly Publication of Individuals Who Have Chosen To Expatriate, 6598-6613 2016-02312 International Trade Adm International Trade Administration NOTICES Antidumping or Countervailing Duty Investigations, Orders, or Reviews: Pure Magnesium from the People's Republic of China, 6504-6506 2016-02425 Supercalendered Paper from Canada, 6506-6507 2016-02397 International Trade Com International Trade Commission NOTICES Complaints: Certain Hospital Beds and Components Thereof, 6538-6539 2016-02296 Investigations; Determinations, Modifications, and Rulings, etc.: Potassium Permanganate from China, 6538 2016-02344 Justice Department Justice Department See

Drug Enforcement Administration

NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: 2016 Law Enforcement Administrative and Management Statistics Survey, 6539-6540 2016-02378 Federal Firearms Licensee Enrollment/National Instant Criminal Background Check System E-Check Enrollment Form, etc., 6540-6541 2016-02377
Labor Department Labor Department NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Generic Solution for Touch-Base Activities, 6541-6542 2016-02433 Petitions for Modification of Mandatory Safety Standards, 6542 2016-02426 Self-Employment Training Demonstration Evaluation, 6543-6544 2016-02428 Short-Time Compensation Grants, 6542-6543 2016-02423 Land Land Management Bureau PROPOSED RULES Waste Prevention, Production Subject to Royalties, and Resource Conservation, 6616-6686 2016-01865 NASA National Aeronautics and Space Administration NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Accident Prevention Plans and Recordkeeping, 6517-6518 2016-02406 Central Contractor Registration, 6515-6516 2016-02408 Evaluation of Export Offers, 6519-6520 2016-02448 Permits, Authorities, or Franchises, 6518-6519 2016-02451 Taxpayer Identification Number Information, 6514-6515 2016-02407 Use of Project Labor Agreements for Federal Construction Projects, 6516-6517 2016-02450 National Highway National Highway Traffic Safety Administration RULES Federal Motor Vehicle Safety Standards: Lamps, Reflective Devices, and Associated Equipment, 6454-6458 2016-02268 National Institute Food National Institute of Food and Agriculture RULES Competitive and Noncompetitive Non-formula Federal Assistance Programs: General Award Administrative Provisions and Specific Administrative Provisions, 6411-6418 2016-02213 National Institute National Institutes of Health NOTICES Meetings: National Heart, Lung, and Blood Institute, 6525 2016-02316 National Institute of Diabetes and Digestive and Kidney Diseases, 6525 2016-02317 National Institute on Deafness and Other Communication Disorders, 6524 2016-02318 National Library of Medicine, 6525 2016-02315 National Oceanic National Oceanic and Atmospheric Administration RULES 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, 6459-6460 2016-02391 Pacific Cod by Catcher/Processors using Trawl Gear in the Western Regulatory Area of the Gulf of Alaska, 6460-6461 2016-02394 PROPOSED RULES Fisheries of the Exclusive Economic Zone Off Alaska: Western Alaska Community Development Quota Program, 6489-6500 2016-02319 Trade Monitoring Procedures for Fishery Products; International Trade in Seafood: Permit Requirements for Importers and Exporters Public Meetings, 6489 2016-02418 NOTICES Meetings: Fisheries of the U.S. Caribbean; Southeast Data, Assessment and Review—U.S. Caribbean Data-Limited Species, 6507-6508 2016-02393 Mid-Atlantic Fishery Management Council, 6508 2016-02293 Permits: Marine Mammals; File No. 18537, 6508-6509 2016-02385 Marine Mammals; File Nos. 16193 and 17157, 6509 2016-02384 National Science National Science Foundation NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals, 6544-6545 2016-02365 National Transportation National Transportation Safety Board RULES Notification and Reporting of Aircraft Accidents or Incidents and Overdue Aircraft, and Preservation of Aircraft Wreckage, Mail, Cargo, and Records, 6458-6459 2016-02413 Nuclear Regulatory Nuclear Regulatory Commission NOTICES Applications for Direct Transfer of Licenses: Comanche Peak Nuclear Power Plant, Units 1 and 2, and Independent Spent Fuel Storage Installation, 6545-6549 2016-02380 Environmental Assessments; Availability, etc.: Portland General Electric Co.; Trojan Independent Spent Fuel Storage Installation, Columbia County, OR, 6549-6551 2016-02381 Meetings: Advisory Committee on the Medical Uses of Isotopes, 6551 2016-02382 Personnel Personnel Management Office PROPOSED RULES Personnel Management in Agencies, 6469-6475 2016-02112 Rural Housing Service Rural Housing Service RULES Single Family Housing Guaranteed Loan Program, 6418-6430 2016-01872 Rural Utilities Rural Utilities Service NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals, 6504 2016-02462 Securities Securities and Exchange Commission NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals, 6551-6552, 6554-6555, 6565 2016-02337 2016-02338 2016-02339 2016-02340 Meetings; Sunshine Act, 6562 2016-02490 Self-Regulatory Organizations; Proposed Rule Changes: BATS Exchange, Inc., 6558-6560 2016-02333 EDGX Exchange, Inc., 6552-6554 2016-02336 Financial Industry Regulatory Authority, Inc., 6555-6556 2016-02331 Miami International Securities Exchange, LLC, 6556-6558, 6562-6565 2016-02334 2016-02335 NASDAQ OMX PHLX, LLC, 6560-6562 2016-02332 NYSE MKT, LLC, 6566-6568 2016-02330 Social Social Security Administration NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals, 6568-6571 2016-02353 State Department State Department NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals Overseas Schools Grant Status Report, 6571-6572 2016-02471 Surface Mining Surface Mining Reclamation and Enforcement Office PROPOSED RULES Oklahoma Regulatory Program, 6477-6479 2016-02463 Virginia Regulatory Program, 6479 2016-02460 NOTICES Environmental Impact Statements; Availability, etc.: North Cumberland Wildlife Management Area, Tennessee Lands Unsuitable for Mining, 6537-6538 2016-02449 Transportation Department Transportation Department See

Federal Aviation Administration

See

Federal Motor Carrier Safety Administration

See

National Highway Traffic Safety Administration

NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Small Business Transportation Resource Center Regional Field Offices Intake Form, 6584-6585 2016-02369 Funding Availability: Small Business Transportation Resource Center Program, 6578-6584 2016-02368
Security Transportation Security Administration NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Certified Cargo Screening Program, 6532 2016-02341 Treasury Treasury Department See

Community Development Financial Institutions Fund

See

Comptroller of the Currency

See

Foreign Assets Control Office

See

Internal Revenue Service

U.S. Citizenship U.S. Citizenship and Immigration Services NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Collection of Qualitative Feedback through Focus Groups, 6532-6533 2016-02409 Customs U.S. Customs and Border Protection RULES Elimination of Nonimmigrant Visa Exemption for Certain Caribbean Residents Coming to the United States as H-2A Agricultural Workers, 6430-6433 2016-02488 NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Application for Exportation of Articles under Special Bond, 6525-6526 2016-02398 Country of Origin Marking Requirements for Containers or Holders, 6528 2016-02401 Commercial Gaugers and Laboratories; Accreditations and Approvals: SGS North America, Inc., 2016-02399 6528-6529 2016-02400 Quarterly IRS Interest Rates Used in Calculating Interest on Overdue Accounts and Refunds on Customs Duties, 6526-6527 2016-02402 Veteran Affairs Veterans Affairs Department PROPOSED RULES Prescriptions in Alaska and U.S. Territories and Possessions, 6479-6481 2016-02350 NOTICES Agency Information Collection Activities; Proposals, Submissions, and Approvals: Evaluation of the Department of Veterans Affairs Mental Health Services, 6613 2016-02294 Separate Parts In This Issue Part II Interior Department, Land Management Bureau, 6616-6686 2016-01865 Part III Environmental Protection Agency, 6688-6743 2016-01866 Reader Aids

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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81 25 Monday, February 8, 2016 Rules and Regulations DEPARTMENT OF AGRICULTURE National Institute of Food and Agriculture 7 CFR Part 3430 RIN 0524-AA58 Competitive and Noncompetitive Non-Formula Federal Assistance Programs—General Award Administrative Provisions and Specific Administrative Provisions AGENCY:

National Institute of Food and Agriculture, USDA.

ACTION:

Final rule.

SUMMARY:

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 ADDRESSES section for instructions for submitting comments.

DATES:

This final rule becomes effective on February 8, 2016.

ADDRESSES:

You may submit comments by any of the following methods:

1. Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.

2. Email: [email protected]. Include docket number NIFA-2016-001 in the subject line of the message.

3. Fax: 202-401-7752.

4. Mail: Paper, disk or CD-ROM submissions should be submitted to: Policy and Oversight Division, National Institute of Food and Agriculture, U.S. Department of Agriculture, STOP 2201, 1400 Independence Avenue SW., Washington, DC 20250-2201.

5. Hand Delivery/Courier: Policy and Oversight Division, National Institute of Food and Agriculture, U.S. Department of Agriculture, Room 2304, Waterfront Centre, 800 9th Street SW., Washington, DC 20024.

Instructions: All comments received must include the agency name and reference to docket number NIFA-2016-001. All comments received will be posted to http://www.regulations.gov, including any personal information provided.

FOR FURTHER INFORMATION CONTACT:

Maria Koszalka, Division Director, Policy and Oversight Division, Phone: 202-401-4325, Email: [email protected].

SUPPLEMENTARY INFORMATION:

I. Background and Summary Authority

This rulemaking is authorized by section 1470 of the National Agricultural Research, Extension, and Teaching Policy Act of 1977 (NARETPA), as amended, 7 U.S.C. 3316.

Organization of 7 CFR Part 3430

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 (e.g., additional reporting requirements).

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 of 7 CFR Part 3430

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 of 7 CFR Part 3430

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 of 7 CFR Part 3430

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 of 7 CFR Part 3430

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 of 7 CFR Part 3430

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.

Subpart L of 7 CFR Part 3430

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.

Subpart O of 7 CFR Part 3430

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.

Definitions of Merit Review and Scientific Peer Review

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.

II. Response to Comments and Revisions Included in the Final Rule Subparts A, B, and E

Matching—Currently, 7 CFR 3430.52, identifies that “the required percentage of matching, type of matching (e.g., cash and/or in-kind contributions), sources of match (e.g., non-Federal), and whether NIFA has any authority to waive the match will be specified in the subpart applicable to the specific Federal assistance program, as well as in the RFA.” This section will be modified to include the matching requirement of Section 7128 of the 2014 Farm Bill and the related exclusions and waivers, as appropriate.

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 (e.g., where, when, how) for non-land-grant designation, notification of NIFA's decision, timing, and termination of a non-land-grant declaration.

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.

Subpart F

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.

Subpart G

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.

Subpart H

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.

Subpart I

On September 9, 2010 (75 FR 54759) NIFA published an interim rule where NIFA proposed adding three subparts including Subpart I with a 60-day comment period. Subpart I included the standard elements of a subpart including applicability, purpose, definitions, eligibility, project types and priorities, funding restrictions, and matching requirements for the 406 program. No comments were received for Subpart I. Through this final rule, NIFA adopts Subpart I portion of the interim final rule published on September 9, 2010, as final without change.

Subpart J

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.

Subpart L

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.

Subpart O

Section 7516 of the 2014 Farm Bill introduced changes to the Sun Grant Program that require administrative revisions to the regulation governing the program.

III. Administrative Requirements for the Rulemaking

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.

Executive Order 12866

This action has been determined to be not significant for purposes of Executive Order 12866.

Regulatory Flexibility Act of 1980

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.

Paperwork Reduction Act (PRA)

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 et seq. (PRA). The Department concludes that this final rule does not impose any new information requirements or increase the burden hours. In addition to the SF-424 form families (i.e., Research and Related and Mandatory) and the SF-425 Federal Financial Report (FFR) No. 0348-0061, NIFA has three currently approved OMB information collections associated with this rulemaking: OMB Information Collection No. 0524-0042, NIFA REEport; No. 0524-0041, NIFA Application Review Process; and No. 0524-0026, Organizational Information.

Catalog of Federal Domestic Assistance

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.

Unfunded Mandates Reform Act of 1995 and Executive Order 13132

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 et seq., and has found no potential or 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. As there is no Federal mandate contained herein that could result in increased expenditures by State, local, or tribal governments, or by the private sector, the Department has not prepared a budgetary impact statement.

Clarity of This Regulation

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.

List of Subjects in 7 CFR Part 3430

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:

PART 3430—COMPETITIVE AND NONCOMPETITIVE NON-FORMULA FEDERAL ASSISTANCE PROGRAMS—GENERAL AWARD ADMINISTRATIVE PROVISIONS 1. The authority citation for part 3430 continues to read as follows: Authority:

7 U.S.C. 3316; Pub. L. 106-107 (31 U.S.C. 6101 note).

Subpart A—General 2. In § 3430.2, add a definition in alphabetical order for “Certification of Non-Land-Grant College of Agriculture status” to read as follows:
§ 3430.2 Definitions.

Certification of Non-Land-Grant College of Agriculture status means an institution that followed NIFA's Process for Non-Land Grant College of Agriculture (NLGCA) Designation and received a certification of NLGCA designation from NIFA (see § 3430.16(c)).

Subpart B—Pre-Award: Solicitation and Application 3. In § 3430.16, add paragraph (d) to read as follows:
§ 3430.16 Eligibility requirements.

(d) Certification of NLGCA status. NIFA will make publically available (e.g., Federal Register) the process through which institutions may apply for designation as a NLGCA. The public notice will, at a minimum, include NLGCA criteria, instructions on how to request designation, information about how NIFA will respond to requests, and termination of NLGCA status.

Subpart E—Post-Award and Closeout 4. In § 3430.52, add paragraphs (a)(1) and (2) to read as follows:
§ 3430.52 Cost sharing and matching.

(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 http://www.nifa.usda.gov/form/form.html, and for attaching the certification in Part IV, B. of this RFA);

(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:

(1) 1890 Institution Teaching, Research, and Extension Capacity Building Grants Program;

(2) Higher Education Challenge Grants Program;

(3) Higher Education Multicultural Scholars Program; and

(4) Food and Agricultural Sciences National Needs Graduate and Postgraduate Fellowship Grants Program.

(J) Individual public or private, nonprofit Alaska Native-Serving and Native Hawaiian-Serving Institutions of higher education (see 20 U.S.C. 1059d).

5. Revise § 3430.54 to read as follows:
§ 3430.54 Indirect costs.

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).

Subpart F—Specialty Crop Research Initiative 6. In § 3430.201, revise paragraphs (a)(1) and (3) and add paragraph (c) to read as follows:
§ 3430.201 Purpose.

(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).

7. In § 3430.202, designate the existing paragraph as paragraph (a) and add paragraph (b) to read as follows:
§ 3430.202 Definitions

(b) The following definitions apply to § 3430.209:

Citrus means edible fruit of the family Rutaceae, including any hybrid of such fruits and products of such hybrids that are produced for commercial purposes in the United States.

Citrus producer means any person that is engaged in the domestic production and commercial sale of citrus in the United States.

8. In § 3430.204: a. Designate the existing paragraph as paragraph (a); b. Remove the second sentence of newly designated paragraph (a); and c. Add paragraph (b).

The addition reads as follows:

§ 3430.204 Project types and priorities.

(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).

9. Revise the heading for § 3430.207 to read as follows:
§ 3430.207 Duration of awards.
10. Add § 3430.208 to read as follows:
§ 3430.208 Review of applications.

In addition to the scientific peer review (see § 3430.33), NIFA will regularly conduct a panel of specialty crop industry representatives to review and rank applications for merit, relevance and impact.

11. Add § 3430.209 to read as follows:
§ 3430.209 Emergency Citrus Disease Research and Extension Program.

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.

Subpart G—Agriculture and Food Research Initiative 12. In § 3430.309: a. In paragraph (b)(7), remove “and” from the end; b. In paragraph (b)(8), remove the period from the end and add a semicolon in its place; c. Add paragraphs (b)(9) and (10); d. In paragraph (d) introductory text, remove “Renewable energy” and add in its place “Bioenergy”; e. Redesignate paragraphs (d)(4), (5), and (6) as paragraphs (d)(5), (6), and (7), respectively, and add new paragraph (d)(4); f. In paragraph (f) introductory text, add “economics,” after “trade”; g. Redesignate paragraphs (f)(5) and (6) as paragraphs (f)(6) and (7), respectively, and add new paragraph (f)(5).

The additions read as follows:

§ 3430.309 Priority areas.

(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;

Subpart H—Organic Agriculture Research and Extension Initiative 13. In § 3430.401, revise paragraphs (a), (b)(1), (b)(2), and (b)(6) to read as follows:
§ 3430.401 Purpose.

(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;

§ 3430.402 [Removed and Reserved]
14. Remove and reserve § 3430.402. Subpart J—Beginning Farmer and Rancher Development Program 15. In § 3430.603, revise paragraph (c) to read as follows:
§ 3430.603 Eligibility.

(c) A community-based or nongovernmental organization;

16. In § 3430.604, revise paragraphs (a)(1) through (14) to read as follows:
§ 3430.604 Project types and priorities.

(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.

§ 3430.605 [Amended]
17. In § 3430.605, in paragraph (b), revise the reference “§ 3430.5460” to read “§ 3430.54.”
18. In § 3430.608, revise paragraph (b) to read as follows:
§ 3430.608 Review criteria.

(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.

19. In § 3430.609, revise paragraph (a) and in paragraphs (c) and (d), remove the phrase “and an award for an educational enhancement team project”.

The revision reads as follows:

§ 3430.609 Other considerations.

(a) Set aside. (1) Not less than 5 percent of the funds used to carry out this subsection for a fiscal year shall be used to support programs and services that address the needs of—

(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.

20. Add subpart L to read as follows: Subpart L—Capacity Building Grants for Non-Land Grant Colleges of Agriculture Program Sec. 3430.800 Applicability. 3430.801 Purpose. 3430.802 Definitions. 3430.803 Eligibility. 3430.804 Project types and priorities. 3430.805 Funding restrictions. 3430.806 Matching requirements. 3430.807 Duration of grant. Authority:

7 U.S.C. 3316; Pub. L. 106-107 (31 U.S.C. 6101 note).

§ 3430.800 Applicability.

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).

§ 3430.801 Purpose.

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.

§ 3430.802 Definitions.

The definitions applicable to the program under this subpart include:

Capacity building means enhancing and strengthening the quality and depth of an institution's research and academic programs as evidenced by its: faculty expertise, scientific and technical resources, research environment, curriculum, student experiential learning opportunities, scientific instrumentation, library resources, academic standing and racial, ethnic, or gender diversity of its faculty and student body, faculty and student recruitment and retention programs, and organizational structures and reward systems for attracting and retaining first-rate research and teaching faculty or students.

Citizen or national of the United States means:

(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.

Eligible participant means an individual who is a citizen or national of the United States as defined in this section.

Food and agricultural sciences means basic, applied, and developmental research, extension, and teaching activities in food and fiber, agricultural, renewable energy and natural resources, forestry, and physical and social sciences, including activities relating to the following:

(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).

Joint project proposal means:

(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.

Large-scale, Comprehensive Initiative (LCI) project proposal means:

(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 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 as specified in this RFA; other entities participating in a joint project proposal are not required to meet the definition of an eligible institution. LCI Project Proposals must support a multi-partner approach to solving a major state or regional challenge in agricultural sciences education at the postsecondary level. LCI Project Proposals are characterized by multiple partners (each providing a specific expertise) organized and led by a strong applicant with documented project management ability to organize and carry out the initiative.

Non-land-grant college of agriculture (NLGCA) means a public college or university offering a baccalaureate or higher degree in the study of agriculture or forestry. The terms “NLGCA Institution” and “non-land-grant college of agriculture” do not include:

(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 et seq., or the `1862 Land Grants');

(3) The Act of August 30, 1890 (commonly known as the “Second Morrill Act”) (7 U.S.C. 321 et seq., or the `1890 Land Grants');

(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 et seq.).

Outcomes means specific, measurable project results and benefits that, when assessed and reported; indicate the project's plan of operation has been achieved. Measurable outcomes include:

(1) Results are intended or unintended consequences of the project, (e.g., “. . . additional course materials now available online to reinforce student learning during non-classroom hours”);

(2) Products may be actual items or services acquired with funds, (e.g., “. . . mechanisms and content to transition existing course(s) or elements of course(s) for Web-based access” or “created new and innovative prevention and intervention initiatives”); and

(3) Impacts are a measure of the results by comparing what might have happened in the absence of the funded project, (e.g., “. . . an observed, overall increase in student learning based upon 8% higher average test scores of those students who both attended class and used the supplemental, Web-based course materials”.)

Regular project proposal means a proposal for a 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.

Sustainable Agriculture means an integrated system of plant and animal production practices having a site-specific application that will, over the long-term—

(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.

Teaching and education mean formal classroom instruction, laboratory instruction, and practicum experience in the food and agricultural sciences and matters relating thereto (such as faculty development, student recruitment and services, curriculum development, instructional materials and equipment, and innovative teaching methodologies) conducted by colleges and universities offering baccalaureate or higher degrees.

§ 3430.803 Eligibility.

(a) Institution eligibility. Applications may only be submitted by a NLGCA institution. For the purposes of this program, the individual branches of a State college or university that are separately accredited as degree-granting institutions are treated as separate institutions, and are therefore eligible to apply for NLGCA Program awards. Separate branches or campuses of a college or university that are not individually accredited as degree-granting institutions are not treated as separate institutions, and are therefore not eligible to submit an application. Accreditation must be conferred by an agency or association recognized by the Secretary of the U.S. Department of Education.

(b) Teacher or student eligibility. A teacher or student recipient receiving Federal funds from this grants program must be an eligible participant. Where eligibility is claimed under 8 U.S.C. 1101(a)(22), documentary evidence from the Immigration and Naturalization Service as to such eligibility must be made available to NIFA upon request.

§ 3430.804 Project types and priorities.

(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).

§ 3430.805 Funding restrictions.

(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 (e.g., T-shirts and other giveaways) and food functions (e.g., cookouts or other social or meal gatherings) are considered `entertainment' expenses, and are, therefore, also not allowed under this grants program.

§ 3430.806 Matching requirements.

There are no matching requirements for grants under this subpart.

§ 3430.807 Duration of grant.

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.

Subpart O—Sun Grant Program
§ 3430.1001 [Amended]
21. In § 3430.1001, in paragraph (d), remove the words “the Department of Energy” and add in their place “other appropriate Federal agencies (as determined by the Secretary)”.
§ 3430.1002 [Amended]
22. In § 3430.1002, remove the definition for the term “gasification.”
§ 3430.1003 [Amended]
23. In § 3430.1003: a. In paragraph (a)(1), remove the words “at South Dakota State University”; b. In paragraph (a)(2), remove the words “at University of Tennessee at Knoxville”; c. In paragraph (a)(3), remove the words “at Oklahoma State University”; d. In paragraph (a)(4), remove the words “at Cornell University”; e. In paragraph (a)(5), remove the words “at Oregon State University”; and f. In paragraph (a)(6), remove the words “at the University of Hawaii”.
§ 3430.1004 [Amended]
24. In § 3430.1004, in paragraph (a)(1), remove the words “multistate research, extension, and education programs on technology development and multi-institutional and multistate integrated research, extension, and education programs on technology implementation” and add in their place the words “integrated, multistate research, extension, and education programs on technology development and technology implementation”.
§ 3430.1005 [Amended]
25. In § 3430.1005, in paragraph (b), remove the words “each of the five Centers” and add in their place the words “the Centers”.
§ 3430.1007 [Amended]
26. In § 3430.1007: a. In the first sentence of paragraph (a), remove the words “gasification” and “the Department of Energy” and add in their place the words “bioproducts” and “other appropriate Federal agencies” respectively; and b. Remove the second and third sentences of paragraph (a). c. Remove and reserve paragraph (b).
Done at Washington, DC, this 21 day of January, 2016. Sonny Ramaswamy, Director, National Institute of Food and Agriculture.
[FR Doc. 2016-02213 Filed 2-5-16; 8:45 am] BILLING CODE 3410-22-P
DEPARTMENT OF AGRICULTURE Rural Housing Service 7 CFR Part 3555 RIN 0575-AC18 Single Family Housing Guaranteed Loan Program AGENCY:

Rural Housing Service, USDA.

ACTION:

Final rule.

SUMMARY:

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.

DATES:

This rule is effective on March 9, 2016.

FOR FURTHER INFORMATION CONTACT:

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 [email protected].

SUPPLEMENTARY INFORMATION: Executive Order 12866, Classification

This final rule has been determined to be non-significant by the Office of Management and Budget (OMB) under Executive Order 12866.

Executive Order 12988, Civil Justice Reform

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.

Unfunded Mandates Reform Act

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.

Environmental Impact Statement

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.

Executive Order 13132, Federalism

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.

Regulatory Flexibility Act

In compliance with the Regulatory Flexibility Act (5 U.S.C. 601 et seq.) the undersigned has determined and certified by signature of this document that this rule change will not have a significant impact on a substantial number of small entities. This rule does not impose any significant new requirements on Agency applicants and borrowers, and the regulatory changes affect only Agency determination of program benefits for guarantees of loans made to individuals.

Executive Order 13175, Consultation and Coordination With Indian Tribal Governments

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 [email protected].

Executive Order 12372, Intergovernmental Consultation

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).

Programs Affected

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).

Paperwork Reduction Act

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 et seq.). The assigned OMB control number is 0575-0179.

E-Government Act Compliance

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.

Non-Discrimination Policy

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 USDA Program Discrimination Complaint Form (PDF), found online at http://www.ascr.usda.gov/complaint_filing_cust.html, or at any USDA office, or call (866) 632-9992 to request the form. You may also write a letter containing all of the information requested in the form. Send your completed complaint form or letter to us by mail at U.S. Department of Agriculture, Director, Office of Adjudication, 1400 Independence Avenue SW., Washington, DC 20250-9410, by fax (202) 690-7442 or email at [email protected].

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 (e.g., Braille, large print, audiotape, etc.) please contact USDA's TARGET Center at (202) 720-2600 (voice and TDD).

I. Background 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 Federal Register on August 22, 2014 (79 FR 49659). Effective with the announcement on August 22, 2014, the effective date of the interim final rule was delayed from September 1, 2014, to December 1, 2014.

II. This Final Rule; Changes to the December 9, 2013, Interim Final Rule

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: http://www.rd.usda.gov/publications/regulations-guidelines/handbooks. RHS did not receive any comments that opposed the rule.

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. Editorial and technical changes. This rule clarifies terminology and provides editorial and technical changes to correct cross-references in the rule, punctuation, grammar and spelling at the following Sections:

§ 3555.5(d)(7) § 3555.101(b)(6)(x) and (xi) § 3555.103(a) § 3555.107(h) § 3555.151(h)(2) § 3555.151(i)(2) § 3555.256(b)(2)(vi) § 3555.306(f)(1)

2. Environmental requirements. This final rule will expand an applicant's ability to purchase a flood insurance policy at § 3555.5(d)(5) and (6) for a dwelling in a Special Flood Hazard Area (SFHA) from a private insurance company meeting the requirements of 42 U.S.C. 4012a (b)(1)(A). Additionally, the word “habitable” has been removed from the December 2013 interim final rule at § 3555.5(d)(7) to coincide with language utilized by the Federal Emergency Management Agency (FEMA).

3. Discount points as an eligible loan purpose. RHS has reconsidered comments received in response to the 2013 interim final rule regarding discount points as a permissible loan purpose for moderate-income applicants at § 3555.101(b)(6)(vi). In reconsidering the comment, RHS will allow discount points in the final rule, as a permissible loan purpose, to “buy-down” the interest rate for moderate income applicants in addition to low-income applicants. The December 2013 interim final rule limited discount points as an eligible loan purpose to low-income applicants only. The Agency changed its position regarding discount points as an eligible loan purpose to allow all applicants the opportunity to lower the interest rate on the home loan. The Agency previously argued that moderate income borrowers were less likely to need to obtain a lower interest rate. Purchasing mortgage points is very common practice. It doesn't always make financial sense. Since this option may reduce the monthly mortgage payments and savings in accrued interest over the life of the loan, the Agency reconsidered its positon by allowing the applicant to determine if financing discount points will make financial sense for the applicant. This optional loan purpose is considered a prepaid mortgage cost, limiting the maximum loan amount to the appraised value of the collateral offered with the mortgage loan request. If utilized, the interest rate prior to reduction must be no greater than the maximum rate revealed at § 3555.104(a).

4. Loan terms. At § 3555.104(a)(3) under loan terms, the December 2013 interim final rule adopted the current Freddie Mac required net yield in addition to the existing Fannie Mae posted yield for 90-day delivery to establish the interest rate of the loan. Freddie Mac has now ceased publication of their net yield rate. The final rule will permit lenders to establish the interest rate with the current Fannie Mae posted yield for 90-day delivery (actual/actual) for 30-year fixed rate conventional loans plus 1 percent, rounded up to the nearest one-quarter of 1 percent and will remove language applicable to the Freddie Mac required net yield.

5. Combination construction and permanent loan. The December 2013 interim final rule limited a contractor or builder at § 3555.105(b)(6) to 25 units per year unless approved by the Agency. In response to comments, RHS is removing this language. Additionally, the final rule provides that the combination construction and permanent loan feature of the SFHGLP may be utilized for a manufactured home if the builder's contract includes the sum of the cost of the unit and all on-site installation costs. The December 2013 interim final rule prohibited manufactured homes as an eligible loan purpose for this feature at § 3555.105(c).

6. Credit qualifications. Section 3555.151(i)(3)(ii) required applicants who had entered into a bankruptcy debt restructuring plan to have 12 months of seasoned established credit after completion of the plan prior considering the applicants credit favorable. Respondents to the December 2013 interim final rule requested RHS align the language with that of like Federal programs. Like Federal programs, such as the U.S. Department of Housing Urban and Development and U.S. Department of Veterans Affairs allow lenders to consider applicants favorable with a partially completed bankruptcy debt restructuring plan. Having considered the comments, the Agency will amend the final rule for continuity with like Federal programs. The final rule will allow applicants who have a 12 month pay out period under the bankruptcy debt restructuring plan elapsed to be considered satisfactory, provided payment performance was satisfactory and permission from the Trustee or Bankruptcy Judge is obtained to allow additional debt for the applicant.

7. Loan modification plan. The December 2013 interim final rule established language to extend the terms of a loan modification for up to 30 years from the date of the loan modification at § 3555.303(b)(3)(iii). However it limited the guarantee to the date and terms established at issuance of the guarantee. The guarantee would not apply beyond the original 30 year loan term. The final rule provides authority to extend the guarantee to coincide with the terms of a loan modification that meets the eligibility criteria as noted in § 3555.303.

8. Extended-term loan modification. The December 2013 interim final rule allowed lenders under special servicing options at § 3555.304(c) to extend the repayment term up to a maximum of 40 years from the date of loan modification through use of an extended-term loan modification. However, the December 2013 interim final rule at § 3555.304(a)(3) limited the existing guarantee to the terms of the loan note guarantee. The final rule provides authority to extend the guarantee to coincide with the terms of an extend-term loan modification meeting eligibility criteria of that section.

III. Discussion of Public Comments Received on the December 9, 2013, Interim Final Rule

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.

§ 3555.4 Mediation and Appeals

Comment: The final rule should be modified to clarify that any participant receiving an adverse decision can appeal an RHS decision.

RHS Response: The Technical Handbook accompanying the implementation of the December 2013 interim final rule sets forth the criteria for appeal in accordance with 7 CFR parts 1 and 11. Furthermore, notice of any administrative appeal rights will be included in adverse decision letters. The final rule has not been amended based upon this comment.

§ 3555.5 Environmental Requirements

Comment: The final rule should be amended to accept private flood insurance policies. The Biggert-Waters Flood Reform Act of 2012 promotes acceptance of flood insurance by private mortgage companies, as opposed to flood policies issued by the Federal Government as part of the National Flood Insurance Program.

RHS Response: The final rule has been amended based upon this comment. RHS will accept flood insurance by private mortgage companies that meet the requirements of 42 U.S.C. 4012a (b)(1)(A). The Technical Handbook accompanying publication of the December 2013 interim final rule outlined the eligibility of private flood insurance policies.

Comment. Amend the flood insurance language to ensure flood insurance coverage coincides with the National Flood Insurance Act of 1968, as amended.

RHS Response. Flood insurance coverage and policy details are clarified in the Technical Handbook implemented with the December 2013 interim final rule. RHS has not amended the final rule based upon this comment.

§ 3555.7 Exception Authority

Comment: The final rule should be amended to reflect the requirement that exception authority reasons be documented.

RHS Response: The Technical Handbook accompanying the implementation of the December 2013 interim final rule clarified the internal requirements surrounding documenting and submitting a request for exception authority to the RHS Administrator. The Agency has not amended the final rule based upon this comment.

§ 3555.54 Sale of Loans to Approved Lenders

Comment: Provide clarification regarding the sale of loans to approved lenders. Specifically, provide clarification surrounding the liability of purchasing and servicing lenders for origination errors.

RHS Response: RHS has not amended the final rule based upon these comments. Section 3555.54 addresses the sale of loans to approved lenders and sets forth the policies surrounding the eligibility of entities and obligations the participating lender is bound to. Approved lenders may be an originator, a servicer or may hold the loan. The eligibility of entities to become an approved lender and enter into a lender agreement is set forth at § 3555.51. A loan may be serviced by an entity that does not hold a valid lender agreement. The approved lender holding the loan remains responsible for the actions of the servicer. In reference to the purchasing lender's liability surrounding origination errors, § 3555.108(d) sets forth requirements surrounding indemnification when an approved originating lender fails to meet the criteria.

§ 3555.101 Loan Purposes

Comment: The respondent requests the cost to design and construct access to broadband services as an eligible loan purpose.

RHS Response: The Technical Handbook accompanying the implementation of the December 2013 interim final rule clarified the requirements surrounding eligibility of broadband services. RHS has not amended the final rule based upon this comment.

Comment: Add language to § 3555.101(d)(3)(vi) to coincide with text in the preamble of the December 2013 interim final rule regarding refinancing as an eligible loan purpose. The respondent suggested adding language “unless otherwise provided by the Agency” to the last sentence of the section referenced in the final rule to coincide with language published in the December 2013 interim final rule preamble for clarification.

RHS Response: Paragraph (d)(3)(vi) of § 3555.101 is amended to correct an omission of language in the interim final rule that led to a discrepancy between the statement in the preamble to the text of that rule. Some documentation, costs and underwriting requirements of subparts D, E and F may not apply to a refinance transaction. The last sentence of paragraph (d)(3)(vi) of § 3555.101 is amended to read: “Documentation, costs, and underwriting requirements for subparts, D, E, and F of this part apply to refinances, unless otherwise provided by the Agency.

§ 3555.102 Loan Restrictions

Comment: The respondent requests RHS clarify the language in the final rule surrounding seller concession limitations. The respondent proposes additional language to exclude lender credits which can be contributed towards an applicant's closing costs. Additionally the respondent requests excluding a lender cure payment, as a result of undisclosed items on the Good Faith Estimate, from the maximum concession limitation.

RHS Response: RHS has not amended the rule based upon this comment. Internal administrative procedures have been removed from the rule and are provided in the Technical Handbook implemented with the December 2013 interim final rule. The purpose of the Technical Handbook is to remove the detailed administrative instructions and allow for a responsive update to the handbook to mortgage industry changes. Details and guidance regarding seller concession limitations can be found in the Agency's Handbook. Should questions surrounding premium pricing and penalties for lender cures arise, the Technical Handbook will be updated to provide further guidance.

§ 3555.104 Loan Terms

Comment: As of January, 2013, Freddie Mac no longer publishes the Required Net Yield (RNY) information. Because it is not published, it is not feasible for lenders to be required to utilize this rate. The reference to this requirement should be removed.

RHS Response: RHS concurs with this respondent and has removed the language in the final rule that requires a comparison to the maximum interest rate of the loan to Freddie Mac's RNY. In addition, the final rule corrects the reference to the Web site containing information relevant to the calculation of maximum interest rate.

Comment: Respondent supports an extended repayment period of 40 years since credit unions may offer repayment terms of up to 40 years for residential mortgage loans.

RHS Response: RHS is unable to amend the final rule based upon this comment. The Housing Act of 1949 [42 U.S.C. 1472], as amended, limits the term of the guarantee to 30 years at section 502(h)(7)(A) of the Act.

§ 3555.105 Combination Construction and Permanent Loans

Comment: RHS should clarify language with additional detail surrounding contractor/builder method, the limitation of 25 units per year per builder and introductory language.

RHS Response: The Agency has amended the rule based upon this comment. The Agency will no longer limit the builder to 25 units per year without further approval by RHS. Instead the Agency will rely upon the lender and the technical guidelines set forth in the accompanying Technical Handbook implemented with the December 2013 interim final rule that provides the administrative instructions and detail of processing the combination construction and permanent loan feature and qualifying the builder for participation in the combination construction to permanent feature.

Comment: Respondent requests reference to “annual guarantee fee” be struck and replaced with “annual fee” at § 3555.105(d)(3).

RHS Response: The Agency agrees with the respondent and will amend the language at § 3555.105(d)(3) for language consistency to coincide with language in the final rule that implemented the annual fee published in the Federal Register (77 FR 40785) on July 11, 2012. The word “guarantee” will be removed from the section reference in the final rule.

§ 3555.107 Application for and Issuance of the Loan Guarantee

Comment: The Agency should amend the rule to allow a validity period for an appraisal of 180 days in lieu of 120 days. The respondent indicates the application process together with increased federal regulations surrounding mortgage loan processing is now lengthy and the appraisal could expire during the application process.

RHS Response: RHS has not amended the final rule based upon this comment. The validity period of the appraisal report coincides with that of other Federal agencies, such as the US Department of Housing Urban and Development, along with Government Sponsored Enterprise (Fannie Mae and Freddie Mac) who require the age of the appraisal report to be no greater than four months old on the date of note. Additional technical guidance can be found in the Technical Handbook published and implemented with the December 2013 interim final rule.

§ 3555.108 Full Faith and Credit

Comment: The December 2013 interim final rule removed the clear distinction between the originating lender and servicing lender regarding indemnification. This may prevent servicing lenders from fully embracing the program limiting the benefits of servicing competition for the borrower and lenders.

RHS Response: RHS agrees to add the word “originating” to the sentence referencing the continued eligibility of the lender. The use of the word will further clarify the intent of indemnification when a lender fails to originate a loan in accordance with requirements. It will coincide with language in the final rule implementing indemnification for the SFHGLP that holds originating lenders accountable in the future should the Agency seek indemnification from the lender if a loss is paid under certain circumstances. The final rule implementing indemnification was published in the Federal Register (76 FR 31217) on May 31, 2011. The Technical Handbook accompanying the implementation of the December 2013 interim final rule expands upon the details surrounding the criteria outlined.

§ 3555.151 Eligibility Requirements

Comment: One commenter requests clarification at § 3555.151(e) on how the “current home no longer adequately meets the applicant's needs” when considering eligibility of a household for the SFHGLP, who owns a home and intends to retain it.

RHS Response: The Agency has not amended the final rule based upon this comment. The Technical Handbook, released with the implementation of the December 2013 interim final rule provides the administrative procedures and details surrounding the language in the December 2013 interim final rule. The Handbook expands upon further guidance and possible examples when a home no longer meets the needs of the applicant.

Comment: The respondent requests expanded language at § 3555.151(e)(4) to require documentation if the applicants are unable to secure conventional financing.

RHS Response: RHS has not amended the substance of this provision in response to this comment. The Technical Handbook, implemented with the December 2013 interim final rule, which provides the administrative procedures, expands upon the criteria to confirm the applicant's eligibility for the SFHGLP, including eligibility for conventional financing. The applicant must be ineligible for conventional financing, based upon the criteria outlined in the Handbook, for a lender to continue with the application under the SFHGLP.

Comment: Amend the language to include missing text at § 3555.151(h)(2) to clarify language of a sentence. The sentence pertaining to repayment ability should read “The Handbook will define when a debt ratio waiver may be granted” as opposed to “The Handbook will define when a debt ratio may be granted.”

RHS Response: RHS agrees with this comment as recommended and will amend the final rule to correct an editorial omission of text in the December 2013 interim final rule.

Comment: Amend language at § 3555.151(i)(2) to clarify text to indicate “a loan's acceptance”.

RHS Response: RHS agrees with this editorial comment and will amend the text of the final rule to clarify the sentence.

Comment: The commenter proposes to amend the final rule at § 3555.151(i)(3)(ii) by allowing applicant(s) who are presently in a Chapter 13 bankruptcy plan to qualify if the applicant has been in the plan for at least 12 months and payments under the plan have been paid as agreed.

RHS Response: The Agency agrees with this comment. The mortgage industry and other like Federal Agencies offering insurance and guarantees allow the applicant to be in an active bankruptcy repayment plan, provided 12 months of the pay-out period under the bankruptcy has elapsed and the applicant's payment performance has been satisfactory with all required payments made on time, and written permission from the bankruptcy court to enter into the mortgage transaction is obtained. For those lenders who utilize the Agency's automated underwriting system, if the Chapter 13 bankruptcy has not been discharged for a minimum period of two years, the underwriting recommendation will generate a Refer underwriting recommendation requiring manual underwriting.

Comment: A concern was expressed that the language requiring credit counseling may be difficult to implement based on available financing for these programs. The commenter requests RHS to publish a list of counseling programs readily available to all applicants and lenders. Moreover, the commenter requests RHS to require Agency personnel when conditioning for credit counseling in response to a lender's request for Conditional Commitment confirm what credit counseling programs are available in the geographic area of the applicant.

RHS Response: The language in the December 2013 interim final rule is consistent with the language and process found at 7 CFR part 1980, subpart D, § 1980.309(d)(4), which expired upon implementation of the December 2013 interim final rule. Credit counseling remains a supported educational opportunity, carried out by the lender. The Section 502 direct lending program, administered under 7 CFR part 3550, at § 3550.11 requires the State Director to assess the availability of certified homeownership education providers in their respective states. A list of providers, including the reasonable costs, if any, to the participant is maintained by each state as a requirement to the referenced rule which is offered by RHS separate to the SFHGLP in each state. A list is available on each state Web site and can be accessed at: http://www.rd.usda.gov/. Therefore no change will be implemented to this final rule as a result of this comment.

§ 3555.152 Calculation of Income and Assets

Comment: Require applicant's to be employed, maintain employment and work towards paying off the loan.

RHS Response: RHS supports individual loan performance in order to fulfill its statutory obligation to the SFHGLP. The Agency has not changed the substance of the language as a result of this comment.

Comment: Section 3555.152(b)(2) requires lenders to obtain and verify household income for all household members in order to determine the income eligibility of the household for the SFHGLP. Verification of income for the past 24 months is a regulatory change over the previous rule governing the SFHGLP (7 CFR part 1980, subpart D, which expired with implementation of the December 2013 interim final rule) and is excessive and provides no additional benefit to the applicant or RHS.

RHS Response: Household income eligibility is a critical component of every application. Requiring lenders to verify and validate the income of all household members for the previous 2 years assures the public that only truly eligible households are provided assistance under the SFHGLP. Additionally this provision is consistent with language provided in RHS Section 502 direct lending program, found at 7 CFR part 3550 and was a recommendation by the Office of Inspector General (OIG) in an audit (Audit Report 04703-02-Ch dated September 2011) of the SFHGLP. RHS has not amended the final rule based upon this comment.

§ 3555.202 Dwelling Requirements

Comment: Objection to removal of minimal thermal efficiency requirements for existing homes. The commenter was concerned language countered the Government's energy reduction and energy independence goals.

RHS Response: As noted in the preamble of the December 2013 interim final rule, thermal standards for existing homes was removed from the rule as published in the Federal Register (72 FR 70220) on December 11, 2007. The Agency will make no change to the present language in the final rule as a result of this comment. Energy efficient homes for both new and existing construction are encouraged as provided under § 3555.209 under the Rural Energy Plus loans.

Comment: One comment was received in regards to the amount of funds required to cover an interior or exterior escrow holdback. Under the rule that expired (7 CFR part 1980, subpart D) with implementation of the December 2013 interim final rule, the commenter felt the language should require escrow accounts for exterior development be funded at 150 percent of the cost of completion. The commenter requests the language in the final rule at § 3555.202(c) be amended to require their interpretation of the language found at the now expired 7 CFR part 1980, subpart D. The commenter cited risks of fund shortages, cost overruns and a builder's failure to complete improvements as their premise for modifying the language.

RHS Response: While the Agency appreciates the comment on this issue, the final rule regarding funding the escrow for future development is consistent with the practice found at the now expired 7 CFR part 1980, subpart D. Under the former rule and the December 2013 interim final rule, lenders are required to fund an escrow account in an amount sufficient to assure the completion of the remaining work. The language further encourages that amount to be 150 percent of the cost of completion, but may be higher if the lender determines a higher amount is needed. The final rule continues to encourage the lender to fund the escrow at a higher amount, if needed, but at a minimum requires the figure to be at least 100 percent of the cost of completion. Lenders may make an internal business decision to fund an escrow account at a higher amount. As a result of this comment, RHS will make no change to the language in the final rule.

§ 3555.205 Special Requirements for Condominiums

Comment: Clarity is requested in the language surrounding what requirements should be followed and when a condominium unit becomes ineligible for lending.

RHS Response: RHS has not amended the substance of this provision in response to this comment. The Technical Handbook implemented with the December 2013 interim final rule, provides the administrative procedures and expands upon the detailed criteria to confirm requirements for lending on condominium units.

§ 3555.251 Servicing Responsibility

Comment: One respondent requested more detail in § 3555.251(c) surrounding the process of notification, the lender's rights and opportunities to cure deficiencies when it is determined by the Agency that an approved lender has failed to provide acceptable servicing.

RHS Response. The language in this final rule remains unchanged by RHS. The Technical Handbook implemented with the December 2013 interim final rule provides the details surrounding the expectations of loan servicing and monitoring responsibilities of lenders. When a lender has uncorrected performance problems, the Handbook outlines the actions the Agency will take regarding notification and appeal rights surrounding a termination.

§ 3555.252 Required Servicing Actions

Comment: One comment was received requesting § 3555.252(c)(2) of the final rule be amended to remove language requiring the borrower to notify the lender when damage occurs to the property.

RHS Response: RHS has not amended the rule based on this comment. The Agency believes that the regulatory language is clear and consistent with standard industry practice requiring borrowers to notify the lender when damage is sustained to a property and hazard insurance proceeds will be disbursed. The Agency will issue additional guidance regarding insurance should it determine such clarification is necessary. Policy encompassing a lender's responsibility to processing of hazard insurance proceeds as a result of damage to the security is detailed in the accompanying Technical Handbook implemented with the December 2013 interim final rule.

Comment: The language at § 3555.252(d) should be revised to include exceptions to reporting to credit bureaus when loans are in Presidentially declared disaster areas and loans involving the Service members Civil Relief Act.

RHS Response: RHS has not amended the rule based upon this comment. The provisions of the December 2013 interim final rule emphasize a lender's existing and continued responsibility to reporting defaulted mortgages to credit bureaus. Loans involving Service members Civil Relief Act will be subject to the provisions of the Act. Loans located in presidentially declared disaster areas may require special guidance. RHS will issue additional guidance should it determine clarification is necessary. The language as written pertains to the general servicing reporting requirements applicable to most SFHGLP loans.

§ 3555.254 Final Payments

Comment: One commenter requested RHS provide additional clarification regarding the release of security instruments. Presently the language at § 3555.254 indicates lenders may release security instruments only after full payment of all amounts have been received. The commenter indicated if a lender's decision is to not file a loss claim, the final decision to release security documents should lie with the lender.

RHS Response: The intent of the language is to ensure and enforce that lenders cannot release security documents until a satisfaction of the debt in full has occurred. In response to this comment, RHS has amended the rule to add clarification.

§ 3555.256 Transfer and Assumptions

Comment: The words “continue with guarantee” are confusing at § 3555.256(d)(2)(ii). The commenter requests clarity.

RHS Response: RHS has not amended the rule based on this comment. The Agency believes that the regulatory language is clear in that RHS will continue with the guarantee, as opposed to voiding the guarantee in situations meeting the criteria of the section. RHS will issue additional guidance regarding a transfer that does not trigger the due-on-sale clause should it determine such clarification is necessary.

Comment: A respondent indicated § 3555.256(d)(2)(iii) should be clarified to confirm a concurrent loan assumption and modification could occur if a transferee meeting the criteria assumes the guaranteed loan when the loan is past due. The commenter found the language “re-amortized” in the section confusing since it is not listed under § 3555.10 Definition and abbreviations of the rule.

RHS Response: RHS has not amended the rule based on this comment. When a transferee meets the criteria set forth in the section referenced, the regulatory language allows the transferee to assume on the rates and terms of the original promissory note and in the case of a delinquent account, allows the transferee “at the time the assumption agreement is executed” to bring the loan current through reamortization. RHS believes the language “at the time the assumption agreement is executed” is clear and concise that the two actions would be concurrent. Regarding the definition of reamortization, the Technical Handbook, accompanying the release of the December 2013 interim final rule provides an extensive list of terminology and definitions, including reamortization, while the rule addresses substantive definitions. Reamortization is a common mortgage industry term referring to modifying the loan.

Comment: The commenter requests clarification of § 3555.256(d)(3) and restrictions imposed for transfer of title triggering the due-on-sale clause.

RHS Response: RHS released a Technical Handbook with implementation of the December 2013 interim final rule, which provides the details and restrictions imposed for transfer of title triggering the due-on-sale clause. As a result of this comment, RHS has not modified the final rule.

§ 3555.257 Unauthorized Assistance

Comment: In reference to § 3555.277(b), a commenter questioned the lender's ability to prove the applicant's eligibility should the lender be challenged on inaccurate information in response to unauthorized assistance. Specifically in question was if the lender utilized RHS's automated underwriting system when submitting the loan to the Agency, how the lender would prove the applicant was eligible if the Agency's automated underwriting system rendered an acceptable recommendation.

RHS Response: Lenders are required to retain a permanent record of the applicant's request. The final underwriting recommendation obtained from the Agency's automated underwriting system becomes part of the lender's permanent record. Data reflected in the automated system must reflect and support information in the permanent file record retained by the lender. The records should support the lender's ability to prove the applicant's eligibility. Further, the Agency's automated underwriting system is a tool utilized to streamline the decision of the lender, but does not replace the lender's final determination to qualify the household for the SFHGLP or the loan request. No change to the final rule as a result of this comment has been made.

§ 3555.301 General Servicing Techniques

Comment: One comment was received in regards to language used surrounding past due accounts found at § 3555.301(e). Verbiage in the December 2013 interim final rule references months past due while the Consumer Financial Protection Bureau (CFPB) (12 CFR part 1026) measures payments past due in days. It was suggested the Agency align our language with CFPB.

RHS Response: RHS will amend the rule in Sections referencing months, as applicable, for continuity with CFPB when referencing the measurement of delinquent past due amounts. The Agency publishes, as a tool for lenders, a Loss Mitigation Guide. The Agency's Loss Mitigation Guide published at https://usdalinc.sc.egov.usda.gov/USDALincTrainingResourceLib.do currently provides for measurement in “months/days” format in response to CFPB language.

§ 3555.302 Protective Advances

Comment: One commenter requested clarification of protective advances for costs other than taxes and insurance. They questioned if this section pertained to advances incurred prior to a foreclosure sale, or those that occur once a foreclosure sale occurs.

RHS Response: RHS has not revised the substance of this provision in response to the comment. The Agency believes the language flow of the rule provides for a waterfall of loss mitigation workout alternatives from general servicing at § 3555.302, followed by traditional servicing (§ 3555.303), then by special loan servicing (§ 3555.304) prior to voluntary or involuntary liquidation (§§ 3555.305 and 3555.306). The language in these sections provides the guidance, expectations and flow of order for servicing non-performing loans. With consideration for the comment, this final rule makes one minor change to the wording of this provision by referring to the protective advance expense as advances prior to liquidation, for clarification.

§ 3555.303 Traditional Servicing Options

Comment: Several comments were received in regard to traditional servicing options. The majority of comments requested clarification on details surrounding servicing options, such as if the agreement needs to be in writing, the maximum interest rate for modifications, fees and costs included in a loan modification, and eligibility for trial payments.

RHS Response: RHS published a Technical Handbook which accompanied the implementation of the December 2013 interim final rule. The Handbook provides the information which responds to the commenters request for detailed information for offering servicing options to homeowners. In response to comments, RHS has added clarification at § 3555.303(b)(3) to confirm that the loan modification must be a written agreement, the interest rate must be fixed, the rate of interest cannot exceed the original rate of the loan note guarantee issued and trial payments for traditional loan modifications are not required.

Comment: One comment received urged the Agency to adopt, as a servicing option, a moratorium of payments, similar to that offered in the Section 502 SFH Direct lending program offered by the Agency under 7 CFR part 3550.

RHS Response: Traditional and special loan servicing options provide for various forbearance agreements, which in part could temporarily suspend or reduce payments. The Agency believes the forbearance agreement option (see § 3555.10 definition of forbearance agreement) does provide for a moratorium (suspension) of payments temporarily, if warranted, based upon the circumstances of the loan serviced. The Technical Handbook accompanying the publication of the December 2013 interim final rule provides additional details and loss mitigation workout alternatives. RHS has not amended the rule based upon this comment.

Comment: RHS should extend the guarantee at § 3555.303(b)(3)(iii) to cover the full term of a loan modification as opposed to limiting the modification to the original term as referenced in the December 2013 interim final rule. The commenter feels it will expand a lender's ability to assist a homeowner become successful.

RHS Response: RHS agrees with the comment. To that end, the Agency has amended the final rule based on this comment to extend the guarantee to the loan term of the loan modification, provided the loan modification meets the eligibility criteria set forth in § 3555.303(b)(3).

§ 3555.304 Special Servicing Options

Comment: A comment was received regarding the required pre-modification trial payment period found at § 3555.304(b)(2). The commenter indicated that trial payment periods pre-modification decrease the flexibility to assist borrowers and could lead to greater losses for the Agency.

RHS Response: RHS disagrees with this comment in regards to trial payments required at § 3555.304(b)(2). In the waterfall of loss mitigation options, once the lender has determined the use of traditional loan servicing options will not cure the borrower default, the use of special loan servicing options are considered. The objective of special loan servicing options is to offer struggling homeowners who are at risk of foreclosure reduced monthly mortgage payments that are affordable and sustainable over the long-term. Trial payment periods allow a borrower to demonstrate recovery from the financial problem by making 3 or 4 payments at the modified amount, after which the delinquent amount is capitalized into the modified loan. A trial period will help ensure the borrower can meet the modified terms and verify the proposed servicing plan will succeed in helping the borrower afford their home. If they are unable to demonstrate their ability to make their modified mortgage payment before being placed into a permanent modification, the lender can assist with a more suitable alternative to foreclosure that meets the borrower's needs. Many loan servicers' guidelines, other than RHS, require a trial period. Trial payments are a mortgage industry standard. Additionally, this provision is included to minimize loss to the government. RHS has not amended the final rule based upon this comment.

Comment: Comments were received regarding the determination of the interest rate. Lenders requested reconsideration to the requirement to reduce an interest rate on an extended-term loan modification at § 3555.304(c). Historically rates have been low. Lenders viewed this requirement as an impediment to assisting borrowers who were delinquent or in imminent default. Additionally lenders questioned if the interest rate, at execution of the modification agreement, was required to meet the maximum allowable interest rate at noted at § 3555.304(c)(2).

RHS Response: Maximum interest rates cannot exceed the published rate as noted in § 3555.304(c)(2) if lowering the interest rate; or the interest rate of the loan guarantee issued. Reducing the rate is not a required condition to an extended-term loan modification in § 3555.305(c). RHS will amend the final rule to correct language at § 3555.304(c)(2) which references the maximum interest rate is tied to the date the loan modification is executed. Language will be corrected to indicate the maximum interest rate will be tied to when the loan modification is approved.

RHS Comment: Multiple comments were received regarding the waterfall of loss mitigation options that must be considered prior to utilizing a mortgage recovery advance in § 3555.304(c). Concern was expressed that lenders would be forced to utilize an extended-term loan modification with a 40 year term. When the loan is in a Ginnie Mae pool the lender must repurchase it to complete a loan modification. Requiring a 40 year term together with not extending the guarantee beyond the original maturity date subjects the lender to vulnerability that Ginnie Mae may not repurchase the loan after the modification occurs and that lenders may incur greater future losses if liquidated.

RHS Response: Pursuant to § 3555.304(c)(4), if the targeted mortgage payment to income ratio cannot be achieved using an extended-term loan modification, then the lender may consider a mortgage recovery advance. Before considering a mortgage recovery advance, the lender must extend the repayment term for 30 years from the date of loan modification. The lender may extend the repayment term for 40 years from the date of loan modification, but the lender is not required to do so before utilizing a mortgage recovery advance. This language affords the lenders the flexibility to adhere to specific investor loan modification term extension requirements while encouraging lenders to achieve the targeted mortgage payment to income ratio using the servicing option(s) that will be least expensive for the government. Use of the mortgage recovery advance is limited because the mortgage recovery advance will be most expensive for the government. By imposing restrictions, RHS will promote the reduction of mortgage foreclosures in a cost-effective manner. Language at this section is unchanged regarding extended-term loan modification from the final rule implementing special servicing options published August 26, 2010 (75 FR 52429) which became effective September 24, 2010. RHS has amended § 3555.305(c)(1) and (c) for clarity in response to comments.

Comment: One comment was received regarding the mortgage recovery advance special servicing option at § 3555.304(d). The commenter felt if the agency reimburses the lender for eligible advances, additional full financial risk and responsibility on the agency potentially will increase the cost to the overall SFHGLP.

RHS Response: Lenders will advance, after obtaining Agency approval, for any Mortgage Recovery Advance that meets the criteria set forth in the December 2013 interim final rule and supplemented by a Technical Handbook. Pursuant to § 3555.304(d)(7) and with language of the published final rule (75 FR 52429 published August 26, 2010) in connection with the introduction of special loan servicing options, the lender may file a request for partial loss claim to obtain reimbursement of the eligible funds advanced. The claim for reimbursement will be processed by the Agency in advance of any final loss claim reimbursement (occurring after liquidation)—provided the lender has secured adequate security and the borrower is eligible for the advance. A future loss claim filed by a lender after liquidation will be adjusted by any amount of mortgage recovery advance reimbursed to the lender by the Agency. Borrowers are not required to make any monthly or periodic payments on the Mortgage Recovery Advance as outlined in § 3555.304(d)(6)(ii). The mortgage recovery advance is due and payable pursuant to § 3555.304(d)(6)(iii). The Agency has made no change to their collection procedures presently exercised on loss payments paid that do not involve a mortgage recovery advance. In accordance with § 3555.304(d)(6)(v), RHS may pursue collection of the Federal debt from the borrower by any available means if the mortgage recovery advance is not repaid based on the terms in the promissory note and mortgage or deed-of-trust. This same approach is performed on loss payments that do not involve a mortgage recovery advance. Therefore, additional financial risk and responsibility to the Agency has not increased with publication of this rule. RHS has not amended the final rule based on this comment.

Comment: A comment was received questioning the maximum Mortgage Recovery Advance (MRA) at § 3555.304(d). The respondent questioned how the advance will be determined and if the MRA maximum is not advanced on an initial MRA, can the balance of the maximum calculation of MRA be applied to another future MRA.

RHS Response: RHS released a Technical Handbook and Loss Mitigation Guide with implementation of the December 2013 interim final rule. The handbook and guide outlines the details surrounding the eligibility and calculation of a maximum recovery advance. To be eligible, the lender must consider an extended-term loan modification of at least 30 years and set the interest rate not to exceed the maximum allowable rate as further outlined in § 3555.304(c)(1) and (2). If the targeted mortgage payment to income cannot be achieved using an extended-term loan modification, the lender may consider a mortgage recovery advance. The maximum mortgage recovery advance (up to 30 percent of the unpaid principal balance as of the date of default) consists of the sum of arrearages not to exceed 12 months of principal, interest, taxes and insurance (PITI); legal fees and foreclosure costs related to a cancelled foreclosure action; and principal reduction as outlined in § 3555.304(d)(1) and (2). The principal deferment on the modified mortgage is determined by multiplying the unpaid principal balance by 30 percent and then reducing that amount by arrearages advanced to cure the default and any foreclosure costs incurred to that point. The principal deferment amount for a specific case shall be limited to the amount that will bring the borrower's total monthly mortgage payment to 31 percent of gross monthly income. In response to the comment, the following is an example of the calculation of a maximum Mortgage Recovery Advance when utilizing the Special Loan Servicing:

Example. Unpaid Principal Balance = $150,000

• Current Monthly Payment (PITI) = $1,220 (Principal and Interest = $920 + Taxes and Insurance = $300) • Current Other Recurring Debt = $800 • Monthly Gross Income = $3,500 • Number of Payments Past Due = 3 • Total Arrearage = $3,660 • Maximum Mortgage Recovery Advance = $150,000 × 30% = $45,000 • Maximum Monthly Mortgage Payment = $3,500 × 31% = $1,085 (Front Ratio) • Maximum Total Monthly Debt = $3,500 × 55% = $1,925 (Back Ratio)

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.

Comment: One commenter felt the language in the December 2013 interim final rule changed the definition of the maximum mortgage recovery advance at § 3555.304(d).

RHS Response: The December 2013 interim final rule language at § 3555.304(d) incorporated the published final rule introducing the special loan servicing options available to lenders (75 FR 52429 published August 26, 2010). Details on eligibility, processing, approval, documentation requirements, and reimbursement to the lender can be found in the Technical Handbook and Loss Mitigation Guide implemented with the December 2013 interim final rule. RHS has not amended the final rule in response to this comment.

Comment: Clarification was requested on § 3555.304(d)(iv) on collecting the Mortgage Recovery Advance from the borrower. Concern was expressed if the lender was responsible for paying off the borrower's MRA once a borrower voluntarily or involuntarily transfers title to the property.

RHS Response: Pursuant to § 3555.304(d)(6) the lender must have the borrower execute a promissory note payable to RHS and a mortgage or deed-of-trust in recordable form perfecting a lien naming RHS as the security party for the amount of the mortgage recovery advance. The lender will record the mortgage or deed-of-trust in the appropriate local real estate records and provide the original promissory note to RHS. The Mortgage Recovery Advance will be interest free. Borrowers are not required to make any monthly or periodic payment; however, the borrower may voluntarily submit partial payment without incurring any prepayment penalty. The payment of the Mortgage Recovery Advance is not due until the earliest of (i) the maturity of the modified mortgage; (ii) the borrower transfers title to the property (by sale or by other voluntary or involuntary means), or (iii) a payoff of the mortgage. Pursuant to § 3555(d)(8) any RHS reimbursement issued for the Mortgage Recovery Advance to the lender on behalf of the borrower will be credited toward the maximum loan guarantee amount payable by the Agency under the guarantee. This credit or reduction in the ultimate loss claim payment is necessary since the Mortgage Recovery Advance is a partial claim under the guarantee. The lender is not expected to collect on the Mortgage Recovery Advance. RHS has not changed the final rule in response to this comment as § 3555.304(d) provides the provisions a lender must follow and additional administrative details are available through the Technical Handbook and Loss Mitigation Guide implemented with the December 2013 interim final rule.

§ 3555.305 Voluntary Liquidation

Comment: To be eligible for a voluntary liquidation option, § 3555.305(a)(3) indicates the borrower must presently occupy the property, unless non-occupancy is related to the same involuntary reason leading to the default. One comment was received asking for further relief and flexibility should the borrower act in good faith in vacating the premises to facilitate a pre-foreclosure sale or due to a financial hardship.

RHS Response: RHS has not amended the rule based upon this comment. Further guidance and detail is provided in the Technical Handbook accompanying the implementation of the December 2013 interim final rule. To be eligible to participate in a voluntary liquidation, the borrower must occupy the property as their primary residence. A non-occupant borrower who seeks a voluntary liquidation option may be eligible should the lender verify that the need to vacate is related to the cause of the default, such as job loss (financial hardship), a mandatory employment transfer, divorce or death, for example. RHS feels the flexibility provided to allow non-occupant borrower eligibility for voluntary liquidation is a lenient standard and any further flexibility is not acceptable from a risk management perspective.

§ 3555.306 Liquidation

Comment: One commenter requested that the lender should be able to assign the loan to the government when the default occurs and prior to liquidation in accordance with the Housing Act of 1949.

RHS Response: The Housing Act of 1949, as amended, at section 502(h)(15) provides the option to the program to allow a lender to transfer a loan in default to the government prior to liquidation. RHS has not exercised this option. RHS has selected a more cost effective strategy by requiring lenders to liquidate and sell an acquired property, while RHS exercises oversight and verifies proper use of government funds. Should RHS exercise the language available in the Housing Act in the future, language will be published. RHS has not amended the final rule in response to this comment.

Comment: A respondent expressed concern regarding the requirement that in addition to a borrower paying all past-due amounts, advances and any foreclosure costs when reinstating an account in liquidation a borrower must have the ability to continue making the scheduled payments on the loan pursuant to language found at § 3555.306(c)(2). Clarification was requested on what actions by the lender are necessary to perform or comply with ensuring the borrower has the ability to continue making the scheduled payments on the loan if the loan is paid current and all fees are paid.

RHS Response: RHS has considered the language and action questioned. RHS has omitted reference to the borrower's ability to continue making scheduled payments when the loan is paid current and all fees are paid as noted in § 3555.306(c).

Comment: One respondent indicated § 3555.306(d)(3) seems to mandate creditors to force a debtor to reaffirm a debt. The respondent indicated most jurisdictions allow a “retain and pay” option, so that the debtor continues to pay the mortgage but is discharged of the personal liability by virtue of the Chapter 7 discharge. The respondent requested clarification on the language in the section in question.

RHS Response: Language in the § 3555.306(d)(3) provides the flexibility the respondent is seeking by instructing the lender to seek a reaffirmation under the criteria noted, whenever possible. RHS has not amended the final rule in response to this comment.

Comment: Concern was expressed by a respondent in reference to language found at § 3555.306(f)(3) of the December 2013 interim final rule. The respondent felt the language limited the lender in the sale of property once the marketing period for an acquired property expired. The language indicates it is the Agency's responsibility to obtain a liquidation value appraisal. Often times the lender's receipt of that appraisal is delayed. The respondent is seeking assurance the lender can continue to sell the property while waiting for the Agency to respond with the determined liquidation value. Additionally the respondent expressed concern on the balance of language at § 3555.306(f)(3) which limited accrued interest paid a loss claim to 90 days from the foreclosure sale or expiration of redemption period when calculating a loss claim request of the Agency.

RHS Response: Pursuant to § 3555.306(f)(3), to ensure the lender proactively seeks maximum recovery from the sale of the acquired property, RHS requires the lender to notify the Agency if the security property held for disposition remains unsold once the marketing period expires. The Agency orders a liquidation value appraisal in response to notification and provides the lender with the results of the report. With the value determined, a loss claim is calculated based upon a management sale factor, which estimates holding and resale costs. In response to the commenter who is seeking Agency approval to allow continued marketing while waiting for a liquidation value appraisal, once the marketing period has expired, and the lender has notified the Agency of the expiration, the loss claim will be calculated based upon a liquidation value appraisal pursuant to § 3555.354(b). Additionally, the referenced section caps accrued interest to the first 90 days of the marketing period. This requirement assures the program goals are met in a cost-effective manner and minimizes loss to the government. The Technical Handbook implemented with the December 2013 interim final rule provides an aggressive marketing and sales approach for lenders which when followed should result in a sale of acquired property within 90 days of foreclosure or redemption. As a result of guidance provided, RHS has not amended the final rule in response to this comment.

§ 3555.307 Assistance in Natural Disasters

Comment: Comments were received proposing slight phrase changes for clarification regarding special relief measures available when a natural disaster is designated found at § 3555.307(c).

RHS Response: The Agency has considered the request of commenters. While no substantive changes are made to the rule as written, the Agency has agreed to modify language slightly for clarification.

§ 3555.354 Loss Claim Procedures

Comment: One comment was received reporting the concern that RHS will no longer conduct an audit to determine why a loan failed and if there was reason to reduce or deny the loss claim.

RHS Response: Details surrounding processing loss claim requests and reduction or denial of a proposed claim can be found in the Technical Handbook accompanying the implementation of the December 2013 interim final rule. The Handbook indicates the Agency will review each loss claim for adherence to program regulation and make any reductions and/or denial of loss claim with information provided by the lender. RHS has not amended the final rule based upon this comment.

Comment: One comment was received requesting the Agency to implement a partial claim payment option as provided for in the Housing Act of 1949, as amended.

RHS Response: The December 2013 interim final rule at § 3555.304(d)(7) provides for reimbursement from the Agency to the lender for a Mortgage Recovery Advance. This claim process is a partial claim payment filed by a lender in response to a Mortgage Recovery Advance under special servicing options (§ 3555.304). The Housing Act of 1949, as amended, at section 502(h)(14) provides this authority. The lender must comply with requirements set forth in § 3555.304(d)(7) when requesting a partial claim. Any future loss claim filed by a lender is adjusted by any amount of Mortgage Recovery Advance reimbursed to the lender by the Agency. RHS has not amended the final rule based on this comment since language in the December 2013 interim final rule provided for a partial claim payment under the guarantee in response to the Mortgage Recovery Advance by the lender.

Comment: Several comments were received in response to penalties imposed as a result of untimely submission of a disposition plan at acquisition or loss claim report once a property held by the lender is sold. Commenters felt the possible penalties implied were unduly harsh.

RHS Response: RHS establishes delivery timelines for lenders to report; file claims or update records for essential documents in the servicing, loss mitigation, liquidation, acquisition and loss claim process. Time lines establish prompt response requiring lenders to comply with corresponding expectations. Time lines for regulatory compliance, for example—filing a claim, require actions by the lender and impose penalties associated with non-compliance with those timelines. Establishing expected timelines are a common method in the mortgage industry to insure a lender is responsibly attentive and focuses with reasonable due diligence in carrying out tasks associated with non-performing borrowers. Curtailment or penalties on claims when reasonable diligence and/or reporting requirements are not met are common in the mortgage industry as with other federal agencies such as HUD or VA who insure or guarantee a lender's loan. The December 2013 interim final rule at § 3555.354 outlines what may occur should a lender fail to act timely. It also provides for extenuating circumstances beyond the lenders control by utilizing the language “may” be imposed when referring to denying or reducing a claim. This language allows flexibility the commenters are seeking based upon circumstances surrounding untimely filings. Additional detail regarding possible imposed penalties can be found in the Agency's Technical Handbook that accompanied the implementation of the December 2013 interim final rule. RHS has not amended the final rule in response to these comments.

§ 3555.355 Reducing or Denying the Claim

RHS Comment: A comment was submitted in response to language in the rule that allows the Agency to reduce or deny a claim when a lender failed to follow regulatory time frames in servicing and liquidating, including payment of real estate taxes or hazard insurance premiums when due. The commenter requested that the rule define that a direct correlation and casual connection between the lender's action or failure to act occurred which impaired the collateral and ultimately increased the loss.

RHS Response: In response to the comment, the RHS feels language at § 3555.355(a) is consistent with the commenter's request for flexibility in that it provides language indicating RHS may reduce or deny any loss claim by the portion of the loss determined was caused by the lender's action or failure to act. Additional detail surrounding time frames imposed and penalties for a lenders failure to act can be found in the Agency's Technical Handbook that was implemented with the December 2013 interim final rule. The final rule does not revise the Agency's approach to reducing or denying a claim for a lender's failure to comply with the conditions of the Loan Note Guarantee.

List of Subjects in 7 CFR Part 3555

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:

PART 3555—GUARANTEED RURAL HOUSING PROGRAM 1. The authority citation for part 3555 continues to read as follows: Authority:

5 U.S.C. 301, 42 U.S.C. 1471et seq.

Subpart A—General 2. Amend § 3555.5 by revising paragraphs (d)(5) through (7) to read as follows:
§ 3555.5 Environmental requirements.

(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.

Subpart C—Loan Requirements
3. Amend § 3555.101 by revising paragraphs (b)(6)(vi), (b)(6)(x), (b)(6)(xi), and (d)(3)(vi) to read as follows:
§ 3555.101 Loan purposes.

(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.

4. Amend § 3555.103 by revising paragraph (a) to read as follows:
§ 3555.103 Maximum loan amount.

(a) Market value. The market value of the property as determined by an appraisal that meets Agency requirements plus the amount of the up-front loan guarantee fee required by § 3555.107(g), or

5. Amend § 3555.104 by revising paragraph (a)(3) to read as follows:
§ 3555.104 Loan terms.

(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: http://www.rd.usda.gov/publications/regulations-guidelines and

6. Amend § 3555.105 by: a. Removing paragraph (b)(6)and redesignating paragraph (b)(7) as (b)(6); and b. Revising paragraphs (c)(1) and (d)(3). The revisions read as follows:
§ 3555.105 Combination construction and permanent loans.

(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.

7. Amend § 3555.107 by revising paragraph (h) to read as follows:
§ 3555.107 Application for and issuance of the loan guarantee.

(h) Annual fee. The Agency may impose an annual fee of the lender not to exceed 0.5 percent of the average annual scheduled unpaid principal balance of the loan for the life of the loan to allow the Agency to reduce the up-front guarantee in § 3555.107(g). The annual fee will be applicable to purchase and refinance loan transactions. The annual fee may be passed on to the borrower by the lender. The Agency may assess a late charge to the lender if the annual fee is not paid by the due date, and the late charge may not be passed on to the borrower. Further administrative guidance is provided in the handbook.

8. Amend § 3555.108 by revising paragraph (d) introductory text to read as follows:
§ 3555.108 Full faith and credit.

(d) Indemnification. If the Agency determines that a lender did not originate a loan in accordance with the requirements in this part and the Agency pays a claim under the loan guarantee, the Agency may revoke the originating lender's eligibility status in accordance with subpart B and may also require the lender:

Subpart D—Underwriting the Applicant
2. Amend § 3555.151 by revising paragraphs (h)(2) introductory text, (i)(2), and (i)(3)(ii) to read as follows:
§ 3555.151 Eligibility requirements.

(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.

Subpart E—Underwriting the Property
3. Amend § 3555.208 by revising paragraph (a)(2) to read as follows:
§ 3555.208 Special requirements for manufactured homes.

(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.

Subpart F—Servicing Performing Loans
4. Revise § 3555.254 to read as follows:
§ 3555.254 Final payments.

Lenders may release security instruments only after payment for the satisfaction of the full debt, including any recapture, has been received and verified.

5. Amend § 3555.256 by revising paragraph (b)(2)(vi) to read as follows:
§ 3555.256 Transfer and assumptions.

(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).

Subpart G—Servicing Non-Performing Loans
6. Amend § 3555.301 by revising paragraphs (e) and (f) to read as follows:
§ 3555.301 General servicing techniques

(e) Communication. Before an account becomes 60 days past due and if there is no payment arrangement in place, the lender must send a certified letter to the borrower requesting an interview for the purpose of resolving the past due account.

(f) Prior to liquidation. Before an account becomes 60 days past due or before initiating liquidation, the lender must assess the physical condition of the property, determine whether it is occupied, and take necessary steps to protect the property.

7. In § 3555.302, revise the introductory text to read as follows:
§ 3555.302 Protective advances.

Lenders may pay the following pre-liquidation expenses necessary to protect the security property and charge the cost against the borrower's account.

8. Amend § 3555.303 by: a. Revising paragraphs (b)(3) introductory text and (b)(3)((i) and (iii); b. Adding paragraph (b)(3)(v); and c. Revising paragraph (c).

The revisions and addition read as follows:

§ 3555.303 Traditional servicing options.

(b) * * *

(3) Loan modification plan. A loan modification is a permanent change in one or more of the terms of a loan that results in a payment the borrower can afford and allows the loan to be brought current. A loan modification must be a written agreement.

(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) Terms of loan note guarantee. Use of traditional servicing options does not change the terms of the loan note guarantee except when the traditional servicing option meets the requirements of § 3555.303(b)(3)(iv). The loan guarantee will apply to loan terms extending beyond the 30 year loan term from the date of origination when a loan modification meets the criteria set forth in § 3555.303(b)(3)(iv).

8. Amend § 3555.304 by revising paragraphs (c) introductory text and (c)(1) and (2) to read as follows:
§ 3555.304 Special servicing options.

(c) Extended-term loan modification. The Lender may modify the loan by reducing the interest rate to a level at or below the maximum allowable interest rate and extending the repayment term up to a maximum of 40 years from the date of loan modification. The loan guarantee will apply to loan terms extending beyond the 30 year loan term from the date of origination when a loan modification meets the criteria set forth in this section.

(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 http://www.rd.usda.gov/publications/regulations-guidelines/instructions. If the maximum allowable interest rate has not been so established, it shall be 50 basis points greater than the most recent Freddie Mac Weekly Primary Mortgage Market Survey (PMMS) rate for 30-year fixed-rate mortgages (U.S. average) rounded to the nearest one-eighth of one percent (0.125%), as of the date the loan modification is approved.

9. Amend § 3555.306 by revising paragraphs (c) and (f)(1) to read as follows:
§ 3555.306 Liquidation.

(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.

10. Amend § 3555.307 by revising paragraph (c) to read as follows:
§ 3555.307 Assistance in natural disasters.

(c) Special relief measures. The servicer must evaluate on an individual case-by-case basis a mortgage that is (or becomes) seriously delinquent as the result of the borrower's incurring extraordinary damages or expenses related to the natural disaster. The servicer should document its individual mortgage file regarding all servicing actions taken during this time period. The lender must consider all special relief alternatives for disaster assistance available to the borrower prior to suspending collection and foreclosure activities. The suspension of servicing actions will expire 90 days from the declaration date of the natural disaster, unless otherwise extended by the Agency.

Dated: January 4, 2016. Tony Hernandez, Administrator, Rural Housing Service.
[FR Doc. 2016-01872 Filed 2-5-16; 8:45 am] BILLING CODE P
DEPARTMENT OF HOMELAND SECURITY 8 CFR Part 212 [USCBP-2016-0003; CBP Dec. 16-03] RIN 1651-AB09 Elimination of Nonimmigrant Visa Exemption for Certain Caribbean Residents Coming to the United States as H-2A Agricultural Workers AGENCY:

U.S. Customs and Border Protection, DHS.

ACTION:

Interim final rule; solicitation of comments.

SUMMARY:

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.

DATES:

Effective Date: The effective date of the rule is February 19, 2016.

Comment Date: Comments must be received by April 8, 2016.

ADDRESSES:

Please submit comments, identified by docket number, by one of the following methods:

Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments via docket number USCBP-2016-0003.

Mail: Border Security Regulations Branch, Office of International Trade, U.S. Customs and Border Protection, 90 K Street NE., 10th Floor, Washington, DC 20229-1177.

Instructions: All submissions received must include the agency name and docket number for this rulemaking. All comments received will be posted without change to http://www.regulations.gov, including any personal information provided.

Docket: For access to the docket to read background documents or comments received, go to http://www.regulations.gov. Comments submitted will be available for public inspection in accordance with the Freedom of Information Act (5 U.S.C. 552) and 19 CFR 103.11(b) on normal business days between the hours of 9 a.m. and 4:30 p.m. at the Border Security Regulations Branch, Office of International Trade, U.S. Customs and Border Protection, 90 K Street NE., 10th Floor, Washington, DC. Arrangements to inspect submitted comments should be made in advance by calling Mr. Joseph Clark at (202) 325-0118.

FOR FURTHER INFORMATION CONTACT:

Rafael Henry, U.S. Customs and Border Protection, Office of Field Operations, (202) 344-3251, or via email at [email protected].

SUPPLEMENTARY INFORMATION:

I. Public Comments

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.

II. Background

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. See section 212(a)(7)(B)(i) of the Immigration and Nationality Act, as amended (INA) (8 U.S.C. 1182(a)(7)(B)(i)). However, either or both of these requirements may be waived by the Secretary of Homeland Security 1 and the Secretary of State, acting jointly, in specified situations, as provided in section 212(d)(4) of the INA (8 U.S.C. 1182(d)(4)). The Department of Homeland Security (DHS) regulations list those classes of persons that are not required to present a visa (or a passport, in some cases). See 8 CFR 212.1.

1 Pursuant to sections 102(a), 441, 1512(d) and 1517 of the Homeland Security Act of 2002, Public Law 107-296, 116 Stat. 2135, 6 U.S.C. 112(a), 251, 552(d), 557, and 8 CFR 2.1, the authorities of the Attorney General, as described in section 212 of the INA (8 U.S.C. 1182), were transferred to the Secretary of Homeland Security, and the reference to the Attorney General in the statute is deemed to refer to the Secretary.

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. See 22 CFR 41.2(e). However, as discussed below, the justification for providing this visa exemption for such beneficiaries and their spouses and children is now obsolete; further, this visa exemption creates a security loophole that could be exploited by persons who pose a danger to the United States.

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 United States upon arrival at a U.S. port of entry. This will lessen the possibility that persons who pose security risks to the United States and other potential immigration violators may improperly gain admission to the United States.

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. See 8 U.S.C. 1375b.

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. See section 3 of the Virgin Islands Nonimmigrant Alien Adjustment Act of 1982, Public Law 97-271, 96 Stat. 1157, as amended (8 U.S.C. 1255 note). Therefore, the visa exemption for certain Caribbean residents for the beneficiary of a valid, unexpired indefinite certification granted by DOL for employment in the U.S. Virgin Islands, if the beneficiary was proceeding to those islands for such purpose, or for the spouse or child accompanying or following to join such a beneficiary, set forth in 8 CFR 212.1(b)(1)(ii)-(iii), is now obsolete.

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 2 or consulate, and undergo Department of State's visa screening process. Additionally, DHS, in conjunction with State, is eliminating the obsolete visa exemption for the beneficiaries of DOL indefinite certifications for employment in the U.S. Virgin Islands and their spouses and children. State is publishing a parallel amendment to 22 CFR 41.2(e) in the Federal Register.

2 See http://www.usembassy.gov/.

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 Certificate of Good Conduct issued by the Royal Virgin Islands Police Department” to refer to “a current certificate issued by the Royal Virgin Islands Police Force” in new 8 CFR 212.1(b)(2)(iii).

III. Statutory and Regulatory Requirements A. Administrative Procedure Act

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.

B. Executive Orders 13563 and 12866

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 3 came from Jamaica, our analysis will focus on that country. This rule will also eliminate the visa exemption for workers in the U.S. Virgin Islands pursuant to an unexpired indefinite certification granted by DOL. Because these certifications have been obsolete for many years,4 eliminating them will have no effect on the economy; hence, we will exclude this provision for the remainder of the analysis.

3 CBP's BorderStat Database (internal database), accessed November 2, 2015.

4See section 3 of the Virgin Islands Nonimmigrant Alien Adjustment Act of 1982, Pub. L. 97-271, 96 Stat. 1157, as amended (8 U.S.C. 1255 note).

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 would be needed under this rule. We use the number of total travelers from Jamaica under the H-2A program to illustrate the upper bound of costs that could result from this rule.

Employers petitioned on behalf of an annual average of 165 workers from Jamaica under this program from FY 2011-2013,5 and an annual average of 4,010 Jamaicans arrived during that time period,6 which includes arrivals by H-2A agricultural workers as well as their spouses and children. This number also includes multiple arrivals in the same year by the same individuals. Because the number of unique individuals arriving from Jamaica under the H-2A program is not available, we calculate costs based on a range of 165 (our primary estimate) to 4,010 prospective visa applicants. The current nonimmigrant visa application processing fee, also called the Machine-Readable Visa (MRV) fee, is $190. We assume this fee will be paid by the employer for the workers and by the employees for their spouses and children. We estimate that the imposition of the fee will cost workers or employers in aggregate between $31,350 (our primary estimate) and $761,900 per year.

5 Communication with USCIS on August 7, 2014.

6 CBP's BorderStat Database (internal database), accessed August 4, 2014.

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 7 and a range of 165 to 4,010 workers per year, we estimate the cost of the time to Jamaican nationals in aggregate as a result of this rule to be between $5,497 (our primary estimate) and $133,583 per year. Combining this with the cost of the visa application fee, we estimate that the total annual cost of this rule is between $36,847 and $895,483.

7 Derived from International Labor Association's LABORSTA Internet Database. Available at http://laborsta.ilo.org/STP/guest. Accessed August 5, 2014. Our weekly wage estimate (14,826 Jamaican Dollars per week) is from the “Wages, by economic activity” report for all sectors in 2008. Our weekly hours worked estimate (40.7 hours per week) is from the “Hours of work, by economic activity” report for all sectors in 2008. We converted the wage rate to U.S. dollars using the currency converter available at http://www.xe.com/currencyconverter on August 5, 2014. 14,826 Jamaican Dollars divided by 40.7 hours per week, multiplied by 0.008913 Jamaican dollars per U.S. dollar = $3.25 U.S. dollars per 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.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (5 U.S.C. 601 et seq.), as amended by the Small Business Regulatory Enforcement and Fairness Act of 1996, requires an agency to prepare a regulatory flexibility analysis that describes the effect of a proposed rule on small entities when the agency is required to publish a general notice of proposed rulemaking. A small entity may be a small business (defined as any independently owned and operated business not dominant in its field that qualifies as a small business per the Small Business Act); a small not-for-profit organization; or a small governmental jurisdiction (locality with fewer than 50,000 people). Because this interim final rule is exempt from notice and comment rulemaking under 5 U.S.C. 553, a regulatory flexibility analysis is not required.

List of Subjects in 8 CFR Part 212

Administrative practice and procedure, Aliens, Immigration, Passports and visas, Reporting and recordkeeping requirements.

Amendments to Regulations

Part 212 of title 8 of the Code of Federal Regulations is amended as set forth below:

PART 212—DOCUMENTARY REQUIREMENTS: NONIMMIGRANT; WAIVERS; ADMISSION OF CERTAIN INADMISSIBLE ALIENS; PAROLE 1. The general authority citation for part 212 and the sectional authority citation for § 212.1(q) continue to read as follows: Authority:

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.

2. In § 212.1, revise paragraph (b) to read as follows:
§ 212.1 Documentary requirements for nonimmigrants.

(b) Nationals of the British Virgin Islands. A visa is not required of a national of the British Virgin Islands who has his or her residence in the British Virgin Islands, if:

(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.

Date: January 19, 2016. Jeh Charles Johnson, Secretary of Homeland Security.
[FR Doc. 2016-02488 Filed 2-4-16; 4:15 pm] BILLING CODE 9111-14-P
DEPARTMENT OF THE TREASURY Community Development Financial Institutions Fund 12 CFR Part 1807 RIN 1559-AA00 Capital Magnet Fund AGENCY:

Community Development Financial Institutions Fund, Department of the Treasury.

ACTION:

Interim rule with request for public comment.

SUMMARY:

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.

DATES:

Effective date: February 8, 2016. All comments must be written and must be received in the offices of the CDFI Fund on or before April 8, 2016. 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.

ADDRESSES:

You may submit comments concerning this interim rule via the Federal e-Rulemaking Portal at http://www.regulations.gov (please follow the instructions for submitting comments). All submissions must include the agency name and Regulatory Information Number (RIN) for this rulemaking. Information regarding the CDFI Fund and its programs may be obtained through the CDFI Fund's Web site at http://www.cdfifund.gov.

FOR FURTHER INFORMATION CONTACT:

Marcia Sigal, CMF Program Manager, Community Development Financial Institutions Fund, at [email protected].

SUPPLEMENTARY INFORMATION:

I. Background

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.

II. Comments on the December 3, 2010, Interim Rule

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 number of bedrooms in the unit (12 CFR 1807.401(a)).

III. Summary of Changes

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. Section 1807.101, Summary: “Community Service Facilities” has been stricken as a stand-alone activity; instead, Community Service Facilities is embedded in the definition of Economic Development Activities. Per the Uniform Administrative Requirements, the use of the word “Awardee” is replaced with “Recipient,” and any reference to a CMF grant is replaced with “CMF Award” as defined in the definitions section, 12 CFR 1807.104.

B. Section 1807.102, Relationship to other CDFI Programs: The requirement for a Certified CDFI to be an operating entity for three years prior to the application deadline has been deleted; instead, this subsection establishes that restrictions for using CMF Awards in conjunction with other CDFI Program awards will be set forth in the applicable notices of funds, guarantee, or allocation availability.

C. Section 1807.104, Definitions: As noted above, the defined term “Awardee” is deleted and replaced with the new defined term “Recipient.” The term “Applicant” is now defined. The term “CMF Award” is now defined. The term “Development” is revised to clarify that any combination of the listed activities that result in Affordable Housing is “Development.” The term “Direct Administrative Expenses” is now defined. The definition of the term “Economic Development Activity” is revised by striking “purchase”; the term “acquisition” is used instead. The term “Effective Date” is now defined. “Eligible Income” is revised to provide adjustments for Family size. “Eligible Project Costs” is revised to strike “operations” as an eligible use of CMF Awards. “Extremely Low-Income” is revised to align with income limits published by HUD, including adjustments for Family size in the case of Homeownership. The defined term “Family” or “Families” is revised by removing the income categories to describe the household. The defined term “Homeownership” is updated and restructured based on HOME Program regulations. The defined term “Housing” is also revised to reflect HOME Program regulation updates. The defined term “Housing” is used in several places throughout the regulations to signify the intent of the defined term. Some of the structures and facilities excluded from the definition of Housing may meet the definition of Community Service Facilities. The term “In Conjunction With Affordable Housing Activities” has been modified in order to be consistent with standards in other CDFI Fund Programs that fund projects and activities based on proximity to intended beneficiaries and/or assessment of access to services for individuals intended to benefit from such programs (e.g., Healthy Foods Financing Initiative Financial Assistance under the CDFI Program). The term “Investment Period” is defined in § 1807.104. The term “Leveraged Costs” is revised to clarify that such costs are limited to Affordable Housing Activities and Economic Development Activities that exceed the dollar amount of the CMF Award. “Loan Guarantee” is revised to clarify that a loan that is guaranteed with the CMF Award must be used for Affordable Housing Activities and/or Economic Development Activities. “Loan Loss Reserves” is revised to clarify that cash reserves set aside to cover losses must be for Affordable Housing Activities and/or Economic Development Activities. The term “Low-Income” is revised to align with income limits published by HUD, including adjustments for Family size in the case of Homeownership. In the case of rental Housing, “Low-Income” is revised to allow for circumstances in which the qualifying Family occupies a unit that has a Federal or State rental subsidy. The term “Non-Metropolitan Area” is revised to align with and accommodate the OMB definition, which is periodically updated. The term “Non-Regulated CDFI” is deleted because it is not used in the interim rule. The term “Operations” is deleted in § 1807.104 since it is no longer an eligible activity in § 1807.301; a new term “Direct Administrative Expenses” is defined in § 1807.104. A new term, “Payment” is defined to describe the transmission of CMF Award dollars from the CDFI Fund to the Recipient. “Preservation” is revised to specify that refinancing must extend the existing affordability and use restrictions on the property by a minimum of 10 years or as otherwise specified in the Assistance Agreement. “Program Income” is defined to align with the Uniform Administrative Requirements. “Project” is defined to mean the Affordable Housing Activity and/or Economic Development Activity that is financed with a CMF Award. The term “Purchase” is revised to clarify that the purchasing Family and Single-family housing must meet the qualifications set forth in subparts D and E. “Underserved Rural Area” is restructured and revised to serve intended populations per the statute and allow the CDFI Fund to set forth an alternative definition of “Underserved Rural Area” for any given application round in the applicable NOFA and/or Assistance Agreement. “Uniform Administrative Requirements” is defined in § 1807.104 to reflect the Department of the Treasury's codification of the Office of Management and Budget's government-wide framework for grants management. The definition of the term “Very Low-Income” is revised to align with income limits published by HUD, including adjustments for Family size in the case of Homeownership.

D. Section 1807.107, Applicability of regulations for CMF awards: Section 1807.107 was added to address the applicability of this rule to the FY 2010 CMF application round and subsequent application rounds. The CDFI Fund has determined that this rule applies only to those CMF awards made pursuant to Notices of Funds Availability (NOFAs) published after the effective date of this interim rule, except for § 1807.902(e)(1)(i) regarding audited financial statements of Nonprofit Organization Recipients. As indicated at 2 CFR 200.110, the Uniform Administrative Requirements, subpart F—Audit Requirements applies to audits of Nonprofits of fiscal years beginning on or after December 26, 2014.

E. Section 1807.200, Applicant eligibility: In § 1807.200(a)(1), the eligibility requirement that a certifiable CDFI can apply is deleted because the CDFI Fund has determined that most Applicants can meet the program's eligibility requirements by being either a Certified CDFI or a Nonprofit Organization. The eligibility requirements for a Nonprofit Organization are revised in § 1807.200(a)(2)(iii) to no longer allow an entity to demonstrate its principal purpose of development or management of affordable housing through its staffing. Section 1807.200(a)(2)(iii) also states that the applicable Notice of Funds Availability (NOFA) will indicate the percentage of a Nonprofit Organization Applicant's assets that must be dedicated to the development or management of affordable housing. Section 1807.200(b) is also revised to reflect these eligibility modifications.

F. Subpart C, Use of Funds/Eligible activities: Section 1807.300 is revised to clarify that Recipients must use their CMF Awards for the financing-related eligible activities set forth in § 1807.301 to attract private capital and increase investment in those activities in § 1807.300(a) and (b). Revisions to § 1807.300(b) reinforce the requirement that when a Recipient undertakes Economic Development Activities In Conjunction With Affordable Housing Activities, the Recipient must track and report on such Affordable Housing Activities if it was financed with a CMF Award. Sections 1807.300 and 1807.301 are revised by deleting “Community Service Facilities” as a stand-alone eligible activity; instead, “Community Service Facilities” is embedded in the definition of Economic Development Activities. As such, this term is deleted as a technical correction throughout the interim rule, when appropriate. Sections 1807.301 and 1807.302 are revised to eliminate “operations” as an eligible activity. The content of former § 1807.302(c) is now located in § 1807.302(b); the content of § 1807.302(d) is now located in § 1807.302(c). New § 1807.302(d) and (e) are added to clarify certain tracking and repayment requirements for Recipients that use CMF Award for Loan Guarantees or Loan Loss Reserves. Section 1807.302(f) states that Recipients may not use more than five (5) percent of its CMF Award for Direct Administrative Expenses. Section 1807.303 is added to address Program Income requirements.

G. Subpart D, Qualification as Affordable Housing: Section 1807.400 is revised to indicate that the CDFI Fund may establish greater commitments for deeper income targeting attributable to Eligible Project Costs in the applicable NOFA and/or Assistance Agreement. Section 1807.401 is revised in order to make general program clarifications and establish certain program requirements, many of which align with the requirements of the LIHTC Program and the HOME Program. For example, language was added to § 1807.401 to allow the CDFI Fund to set forth in the applicable NOFA requirements for successful applicants to serve targeted incomes that exceed the requirements of § 1807.401. The rent limitation in § 1807.401(a) is revised to align with requirements to qualify for LIHTCs and to account for rental subsidies in each of the income categories. Section 1807.401(c) and (e) are revised to align with requirements to qualify for LIHTCs. Section 1807.401(f) is revised to align with the HOME Program regulations' elimination of the U.S. Census long form for annual income determinations. Thus, the content of the former § 1807.401(f)(2)(i) is deleted and the content of the former § 1807.401(f)(2)(ii) is now located in § 1807.401(f)(2)(i). Similarly, the content of the former § 1807.401(f)(2)(iii) has moved up and is now located in § 1807.401(f)(2)(ii). Section 1807.401(g)(2) is revised to clarify rent restrictions when rent is subject to IRC sections 42(g)(2) and 42(h)(6). Section 1807.401(g)(3) is revised to clarify that any replacement unit must meet the affordability qualifications for the income category of the unit that is being replaced. Section 1807.402(a) and (b) are revised by replacing “acquisition” with “Purchase” to reflect the use of the new defined term. Section 1807.402(a)(5) is revised to clarify that, in the event of resale of CMF-financed Single-family housing to a non-qualifying family before the 10-year affordability period ends, the Recipient must use an equivalent amount of the CMF Award used for the applicable Affordable Housing Activity, whether recouped or not, to finance additional Affordable Housing Activities for a qualifying Family in the same income category for Homeownership.

H. Subpart E, Leveraging and Commitment Requirement: Section 1807.500(b) is revised to include the Assistance Agreement as a source for the required percentage of Leveraged Costs that must be funded by non-governmental sources. Section 1807.500(a)(1) is deleted because “operations” is no longer an eligible activity and defined term. Accordingly, the former § 1807.500(a)(2) is now § 1807.500(b)(2) and former § 1807.500(a)(3) is now § 1807.500(b)(2)(ii). Section 1807.500(b)(2)(iii) was added to address eligible Leveraged Costs for Economic Development Activities. The content of former § 1807.500(b) is deleted. Section 1807.501(a) is revised and section 1807.501(b) is added to account for the eligible activity “Purchase” to a qualifying Family, and § 1807.501(b)(3) is added to provide more accountability regarding Project Completion. Section 1807.501(c) and (d) are added to align with the Uniform Administrative Requirements regarding Payments. Section 1807.503 is revised to include property standards necessary to ensure that CMF Awards are invested in structures and units that are sound, decent, safe and sanitary; such standards are largely adopted from the HOME Program and the requirements to qualify for LIHTCs. Section 1807.503(a)(4) is added to address Project Completion in the case of Preservation. The content of the former § 1807.503(b)(2) is now located in § 1807.503(b)(2)(i) and a new § 1807.503(b)(2)(ii) is added to address disaster mitigation in regards to Project Completion. Section 1807.503(b)(2)(iii) is added to address lead-based paint. The content of former § 1807.503(b)(3) is now moved to § 1807.503(b)(4) and incorporates recent HOME Program updates. Thus, § 1807.503(b)(3) contains new content regarding Rehabilitation standards. The content of former § 1807.503(c) is moved to § 1807.503(a)(3).

I. Subpart F, Tracking Requirements: Section 1807.601 is renamed and revised to reflect that the Uniform Administrative Requirements apply to all CMF Awards and sets forth the CDFI Fund's policy that indirect costs are not allowed. Section 1807.602 also establishes the circumstances in which a CMF Award loses its so-called “Federal character.” Section 1807.602 is also revised to clarify that CMF Awards are Federal financial assistance for purposes of the applicability of Federal civil rights laws.

J. Subpart H, Evaluation and Selection of Applications: In § 1807.800(c)(3) “blight” is deleted as an ambiguous term.

K. Subpart I, Terms and Conditions of Assistance: Section 1807.900(c) is revised to clarify statutory requirements regarding notice and hearing. To align with the Uniform Administrative Requirements, § 1807.901 “Disbursement of funds” is renamed “Payment of funds” to reflect the transmission of CMF Award dollars from the CDFI Fund to the Recipient as a “Payment.” Section 1807.902(d) and (e) are revised to accommodate the audit requirements of the Uniform Administrative Requirements. Pursuant to revised § 1807.902(e)(1), Nonprofit Organizations that are not required to have their financial statements audited pursuant to the Uniform Administrative Requirements may still be subject to additional audit requirements, which will be set forth in the applicable NOFA and Assistance Agreement. In addition, § 1807.902(e)(2), “Performance Goal Reporting,” is renamed as “Annual Report” and revised to clarify and require the submission of performance and financial reporting in the form of an annual report, as further specified in the Assistance Agreement. Section 1807.902(e)(3) is added to clarify the compliance requirements for Insured CDFIs, Depository Institution Holding Companies, and State-Insured Credit Unions. Section 1807.902(e)(4) is added to convey that any reports under § 1807.902 may be subject to public inspection per the Freedom of Information Act. Section 1807.903 is revised to specify that in addition to all other Federal, state, and local laws, Recipients shall also comply with all applicable Federal environmental requirements.

IV. Rulemaking Analysis A. Executive Order (E.O.) 12866

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.

B. Regulatory Flexibility Act

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.

C. Paperwork Reduction Act

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.

D. National Environmental Policy Act

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.

E. Administrative Procedure Act

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).

F. Comment

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.

G. Catalogue of Federal Domestic Assistance Number

Capital Magnet Fund—21.011.

List of Subjects in 12 CFR Part 1807

Community development, Grant programs—housing and community development, Reporting and record keeping requirements.

For the reasons set forth in the preamble, 12 CFR part 1807 is revised to read as follows: PART 1807—CAPITAL MAGNET FUND Subpart A—General Provisions Sec. 1807.100 Purpose. 1807.101 Summary. 1807.102 Relationship to other CDFI Fund programs. 1807.103 Recipient not instrumentality. 1807.104 Definitions. 1807.105 Waiver authority. 1807.106 OMB control number. 1807.107 Applicability of regulations for CMF Awards. Subpart B—Eligibility 1807.200 Applicant eligibility. Subpart C—Eligible Purposes; Eligible Activities; Restrictions 1807.300 Eligible purposes. 1807.301 Eligible activities. 1807.302 Restrictions on use of CMF Award. 1807.303 Authorized uses of Program Income. Subpart D—Qualification as Affordable Housing 1807.400 Affordable Housing—general. 1807.401 Affordable Housing—Rental Housing. 1807.402 Affordable Housing—Homeownership. Subpart E—Leveraged Costs; Eligible Project Costs; Commitment Requirements 1807.500 Leveraged Costs; Eligible Project Costs. 1807.501 Commitments; Payments. 1807.502 CMF Award limits. 1807.503 Projection Completion; Property standards. Subpart F—Tracking Funds; Uniform Administrative Requirements; Nature of Funds 1807.600 Tracking funds. 1807.601 Uniform Administrative Requirements. 1807.602 Nature of funds. Subpart G—Notice of Funds Availability; Applications 1807.700 Notice of funds availability. Subpart H—Evaluation and Selection of Applications 1807.800 Evaluation and selection—general. 1807.801 Evaluation of applications. Subpart I—Terms and Conditions of CMF Award 1807.900 Assistance agreement. 1807.901 Payment of funds. 1807.902 Data collection and reporting. 1807.903 Compliance with government requirements. 1807.904 Lobbying restrictions. 1807.905 Criminal provisions. 1807.906 CDFI Fund deemed not to control. 1807.907 Limitation on liability. 1807.908 Fraud, waste and abuse. Authority:

12 U.S.C. 4569.

Subpart A—General Provisions
§ 1807.100 Purpose.

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.

§ 1807.101 Summary.

(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.

§ 1807.102 Relationship to other CDFI Fund programs.

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.

§ 1807.103 Recipient not instrumentality.

No Recipient shall be deemed to be an agency, department, or instrumentality of the United States.

§ 1807.104 Definitions.

For the purpose of this part:

Act means the Housing and Economic Recovery Act of 2008, as amended, Public Law 110-289, section 1131;

Affiliate means any entity that Controls, is Controlled by, or is under common Control with, an entity;

Affordable Housing means housing that meets the requirements set forth in subpart D of this part;

Affordable Housing Activities means the Development, Preservation, Rehabilitation, and/or Purchase of Affordable Housing;

Affordable Housing Fund means a revolving loan, grant or investment fund that is:

(1) Managed by the Recipient; and

(2) Uses its capital to finance Affordable Housing Activities;

Applicant means any entity submitting an application for a CMF Award;

Appropriate Federal Banking Agency has the same meaning as in section 3 of the Federal Deposit Insurance Act, 12 U.S.C. 1813(q), and includes, with respect to Insured Credit Unions, the National Credit Union Administration;

Appropriate State Agency means an agency or instrumentality of a State that regulates and/or insures the member accounts of a State-Insured Credit Union;

Assistance Agreement means a formal, written agreement between the CDFI Fund and a Recipient, which agreement specifies the terms and conditions of assistance under this part;

Capital Magnet Fund (or CMF) means the program authorized by the Act and implemented under this part;

CMF Award means the financial assistance in the form of a grant made by the CDFI Fund to a Recipient pursuant to this part;

Certified Community Development Financial Institution (or Certified CDFI) means an entity that has been determined by the CDFI Fund to meet the certification requirements set forth in 12 CFR 1805.201;

Committed means that the Recipient is able to demonstrate, in written form and substance that is acceptable to the CDFI Fund, a commitment for use of CMF Award, as set forth in § 1807.501;

Community Development Financial Institutions Fund (or CDFI Fund) means the Community Development Financial Institutions Fund, the U.S. Department of the Treasury, established pursuant to the Community Development Banking and Financial Institutions Act of 1994, as amended, 12 U.S.C. 4701 et seq.;

Community Service Facility means the physical structure in which service programs for residents or service programs for the broader community (including, but not limited to, health care, childcare, educational programs including literacy and after school programs, job training, food and nutrition services, cultural programs, and/or social services) operate that, In Conjunction With Affordable Housing Activities, implements a Concerted Strategy to stabilize or revitalize a Low-Income Area or Underserved Rural Area;

Concerted Strategy means a formal planning document that evidences the connection between Affordable Housing Activities and Economic Development Activities. Such documents include, but are not limited to, a comprehensive, consolidated, or redevelopment plan, or some other local or regional planning document adopted or approved by the jurisdiction;

Control means:

(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;

Depository Institution Holding Company means a bank holding company or a savings and loan holding company as each are defined in the Federal Deposit Insurance Act, 12 U.S.C. 1813(w);

Development means any combination of the following Project activities: Land acquisition, demolition of existing facilities, and construction of new facilities, which may include site improvement, utilities development and rehabilitation of utilities, necessary infrastructure, utility services, conversion, and other related activities resulting in Affordable Housing;

Direct Administrative Expenses means direct costs incurred by the Recipient, related to the financing of the Project as described in 2 CFR 200.413 of the Uniform Administrative Requirements;

Economic Development Activity means the development, preservation, acquisition and/or rehabilitation of Community Service Facilities and/or other physical structures in which neighborhood-based businesses operate which, In Conjunction With Affordable Housing Activities, implements a Concerted Strategy to stabilize or revitalize a Low-Income Area or Underserved Rural Area;

Effective Date means the date that the Assistance Agreement is effective; such date is determined by the CDFI Fund after the Recipient has returned an executed, original Assistance Agreement, along with all required supporting documentation, including the opinion of counsel, if required;

Eligible-Income means:

(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;

Eligible Project Costs means Leveraged Costs plus those costs funded directly by a CMF Award;

Extremely Low-Income means:

(1) Having, in the case of owner-occupied 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 and

(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;

Family or Families means households that reside within the boundaries of the United Sates (which shall encompass any State of the United States, the District of Columbia or any territory of the United States, including Puerto Rico, Guam, American Samoa, the U. S. Virgin Islands, and the Northern Mariana Islands);

HOME Program means the HOME Investment Partnership Program established by the HOME Investment Partnerships Act under title II of the Cranston-Gonzalez National Affordable Housing Act, as amended, 42 U.S.C. 12701 et seq.;

Homeownership means ownership in fee simple title interest in one- to four-unit Housing or in a condominium unit, or equivalent form of ownership approved by the CDFI Fund. The Recipient must determine whether ownership or membership in a cooperative or mutual housing project constitutes Homeownership under State law. The ownership interest is subject to the following additional requirements:

(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;

Housing means Single-family and Multi-family residential units including, but not limited to, manufactured housing and manufactured housing lots, permanent housing for disabled and/or homeless persons, transitional housing, single-room occupancy housing, and group homes. Housing also includes elder cottage housing opportunity (ECHO) units that are small, free- standing, barrier-free, energy-efficient, removable, and designed to be installed adjacent to existing single-family dwellings. Housing does not include emergency shelters (including shelters for disaster victims) or facilities such as nursing homes, convalescent homes, hospitals, residential treatment facilities, correctional facilities, halfway houses, housing for students, or dormitories (including farmworker dormitories);

HUD means the Department of Housing and Urban Development established under the Department of Housing and Urban Development Act of 1965, 42 U.S.C. 3532 et seq.;

In Conjunction With Affordable Housing means:

(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;

Insured CDFI means a Certified CDFI that is an Insured Depository Institution or an Insured Credit Union;

Insured Credit Union means any credit union, the member accounts of which are insured by the National Credit Union Share Insurance Fund by the National Credit Union Administration pursuant to authority granted in 12 U.S.C. 1783 et seq.;

Insured Depository Institution means any bank or thrift, the deposits of which are insured by the Federal Deposit Insurance Corporation as determined in 12 U.S.C. 1813(c)(2);

Investment Period means the period beginning with the Effective Date and ending on the fifth year anniversary of the Effective Date, or such other period as may be established by the CDFI Fund in the Assistance Agreement;

Leveraged Costs means costs for Affordable Housing Activities and Economic Development Activities that exceed the dollar amount of the CMF Award, as further described in § 1807.500;

Loan Guarantee means the Recipient's use of CMF Award to support an agreement to indemnify the holder of a loan all or a portion of the unpaid principal balance in case of default by the borrower. The proceeds of the loan that is guaranteed with the CMF Award must be used for Affordable Housing Activities and/or Economic Development Activities;

Loan Loss Reserves means proceeds from the CMF Award that the Recipient will set aside in the form of cash reserves, or through accounting-based accrual reserves, to cover losses on loans, accounts, and notes receivable for Affordable Housing Activities and/or Economic Development Activities, or for related purposes that the CDFI Fund deems appropriate;

Low-Income means:

(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;

Low-Income Area or LIA means a census tract or block numbering area in which the median income does not exceed 80 percent of the median income for the area in which such census tract or block numbering area is located. With respect to a census tract or block numbering area located within a Metropolitan Area, the median Family income shall be at or below 80 percent of the Metropolitan Area median Family income or the national Metropolitan Area median Family income, whichever is greater. In the case of a census tract or block numbering area located outside of a Metropolitan Area, the median Family income shall be at or below 80 percent of the statewide Non-Metropolitan Area median Family income or the national Non-Metropolitan Area median Family income, whichever is greater;

Low Income Housing Credits (or LIHTCs) means credits against income tax under section 42 of the Internal Revenue Code of 1986, as amended, 26 U.S.C. 42;

Metropolitan Area means an area designated as such by the Office of Management and Budget pursuant to 44 U.S.C. 3504(e) and 31 U.S.C. 1104(d) and Executive Order 10253 (3 CFR, 1949-1953 Comp., p. 758), as amended;

Multi-family housing means residential properties consisting of five or more dwelling units, such as a condominium unit, cooperative unit, apartment, or townhouse;

Non-Metropolitan Area means counties that are designated as Non-Metropolitan Counties by the Office of Management and Budget (OMB) pursuant to 44 U.S.C. 3504(e) and 31 U.S.C. 1104(d) and Executive Order 10253 (3 CFR, 1949-1953 Comp., p. 758), as amended, and as made available by the CDFI Fund for a specific application funding round;

Nonprofit Organization means any corporation, trust, association, cooperative, or other organization that is:

(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;

Participating Jurisdiction means a jurisdiction designated by HUD as such under the HOME Program in accordance with the requirements of 24 CFR 92.105;

Payment means the transmission of CMF Award dollars from the CDFI Fund to the Recipient;

Preservation means:

(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;

Program Income means gross income, as further described in 2 CFR part 1000;

Project means the Affordable Housing Activity and/or Economic Development Activity that is financed with the CMF Award;

Project Completion means that all of the requirements set forth at § 1807.503 for a Project have been met;

Purchase means to provide direct financing to a Family for purposes of Homeownership. Before the Recipient provides any financing to a Family for Homeownership purposes, the Recipient must verify that the Family and the Single-family housing meet the qualifications set forth in subparts D and E of this part;

Recipient means an Applicant selected by the CDFI Fund to receive a CMF Award pursuant to this part;

Rehabilitation means any repairs and/or capital improvements that contribute to the long-term preservation, current building code compliance, habitability, sustainability, or energy efficiency of Affordable Housing;

Revolving Loan Fund means a pool of funds managed by the Applicant or the Recipient wherein repayments on loans for Affordable Housing Activities or Economic Development Activities are used to refinance additional loans;

Risk-Sharing Loan means loans for Affordable Housing Activities and/or Economic Development Activities in which the risk of borrower default is shared by the Applicant or Recipient with other lenders (e.g., participation loans);

Service Area means the geographic area in which the Applicant proposes to use the CMF Award, and the geographic area approved by the CDFI Fund in which the Recipient must use the CMF Award as set forth in its Assistance Agreement;

Single-family housing means a one- to four-Family residence, a condominium unit, a cooperative unit, a combination of manufactured housing and lot, or a manufactured housing lot;

State means the states of the United States, the District of Columbia, the Commonwealth of Puerto Rico, the Commonwealth of the Northern Mariana Island, Guam, the U.S. Virgin Islands, American Samoa, the Trust Territory of the Pacific Islands, and any other territory of the United States;

State-Insured Credit Union means any credit union that is regulated by, and/or the member accounts of which are insured by, a State agency or instrumentality;

Subsidiary means any company that is owned or Controlled directly or indirectly by another company;

Underserved Rural Area means:

(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;

Uniform Administrative Requirements means the Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards (2 CFR part 1000);

Very Low-Income means:

(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.

§ 1807.105 Waiver authority.

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 Federal Register.

§ 1807.106 OMB control number.

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.

§ 1807.107 Applicability of regulations for CMF Awards.

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.

Subpart B—Eligibility
§ 1807.200 Applicant eligibility.

(a) General requirements. An Applicant will be deemed eligible to apply for a CMF Award if it is:

(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) Eligibility verification. An Applicant shall demonstrate that it meets the eligibility requirements described in paragraph (a)(2) of this section by providing information described in the application, NOFA, and/or supplemental information, as may be requested by the CDFI Fund. For an Applicant seeking eligibility under paragraph (a)(1) of this section, the CDFI Fund will verify that the Applicant is a Certified CDFI during the application eligibility review.

Subpart C—Eligible Purposes; Eligible Activities; Restrictions
§ 1807.300 Eligible purposes.

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.

§ 1807.301 Eligible activities.

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.

§ 1807.302 Restrictions on use of CMF Award.

(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 taxpayer conducting such trade or business, the sum of the aggregate unadjusted bases (or, if greater, the fair market value) of the assets owned by the taxpayer that are used in such a trade or business, and the aggregate value of the assets leased by the taxpayer that are used in such a trade or business, exceeds $500,000.

(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.

§ 1807.303 Authorized uses of Program Income.

(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.

Subpart D—Qualification as Affordable Housing
§ 1807.400 Affordable Housing—general.

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.

§ 1807.401 Affordable Housing—Rental Housing.

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) Rent limitation. The gross rent limits for Affordable Housing are determined under the provisions in IRC section 42(g)(2). In this determination, if this part imposes an income restriction on a unit that is greater than 60 percent of area median income, adjusted for Family size, then the provisions of IRC section 42(g)(2) are applied as if that income restriction on the unit satisfied IRC section 42(g)(1). The maximum rent is a rent that does not exceed:

(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 (i.e., tenant contribution plus rental subsidy) is the rent allowable under the Federal or State rental subsidy program;

(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 (i.e., tenant contribution plus rental subsidy) is the rent allowable under the Federal or State rental subsidy program; or

(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 (i.e., tenant contribution plus rental subsidy) is the rent allowable under the Federal or State rental subsidy program.

(b) Nondiscrimination against rental assistance subsidy holders. The Recipient shall require that the owner of a rental unit cannot refuse to lease the unit to a Section 8 Program certificate or voucher holder (24 CFR part 982, Section 8 Tenant-Based Assistance: Unified Rule for Tenant-Based Assistance under the Section 8 Rental Certificate Program and the Section 8 Rental Voucher Program) or to the holder of a comparable document evidencing participation in a HOME tenant-based rental assistance program because of the status of the prospective tenant as a holder of such certificate, voucher, or comparable HOME tenant-based assistance document.

(c) Initial rent schedule and utility allowances. The Recipient shall ensure that utility allowances and submetering rules are consistent with regulations concerning utility allowances and submetering in buildings that are subject to gross rent restrictions under IRC section 42(g)(2).

(d) Periods of affordability. Housing under this section must meet the affordability requirements for not less than 10 years, beginning after Project Completion and at initial occupancy. The affordability requirements apply without regard to the term of any loan or mortgage or the transfer of ownership and must be imposed by deed restrictions, covenants running with the land, or other recordable mechanisms. Other recordable mechanisms must be approved in writing and in advance by the CDFI Fund. The affordability restrictions may terminate upon foreclosure or transfer in lieu of foreclosure. However, the affordability restrictions shall be revived according to the original terms if, during the original affordability period, the owner of record before the foreclosure, or deed in lieu of foreclosure, or any entity that includes the former owner or those with whom the former owner has or had family or business ties, obtains an ownership interest in the Project.

(e) Subsequent rents during the affordability period. Any increase in rent for a CMF-financed unit requires that tenants of those units be given at least 30 days prior written notice before the implementation of the rent increase. Regardless of changes in annual rents and in median income over time, the CMF rents for a Project are not required to be lower than the CMF rent limits for the Project in effect at the time when the Project is Committed for use.

(f) Tenant income determination. (1) Each year during the period of affordability, the tenant's income shall be re-examined; tenant income examination and verification is ultimately the responsibility of the Recipient. Annual income shall include income from all household members. The Recipient must require the Project owner to obtain information on rents and occupancy of Affordable Housing financed or assisted with a CMF Award in order to demonstrate compliance with this section.

(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) Over-income tenants. (1) CMF-financed or assisted units continue to qualify as Affordable Housing despite a temporary noncompliance caused by increases in the incomes of existing tenants if actions satisfactory to the CDFI Fund are being taken to ensure that all vacancies are filled in accordance with this section until the noncompliance is corrected.

(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.

§ 1807.402 Affordable Housing—Homeownership.

(a) Purchase with or without Rehabilitation. A Recipient that uses the CMF Award for the eligible activities set forth in § 1807.301 for Purchase must ensure the purchasing Family and Housing meets the affordability requirements of this subpart.

(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) Periods of affordability. Single-family housing under this section must meet the affordability requirements for at least 10 years at the time of purchase by the Family.

(5) Resale. To ensure that CMF Awards are being used for qualifying Families for the entire 10-year affordability period, recoupment and redeployment or resale strategies must be imposed by the Recipient. A recoupment strategy must ensure that, in the event the qualifying homeowner sells the Housing before the end of the 10-year affordability period and the new homeowner does not meet the affordability qualifications set forth in § 1807.400, an amount equal to the amount of the CMF Award investment in the Housing, whether recouped or not, is used to finance additional Affordable Housing Activities for a qualifying Family in the same income category for Affordable Housing Homeownership in the manner set forth in this section, except that the Housing must meet the affordability requirements only for the remaining duration of the affordability period. The Recipient may design and implement its own recoupment strategy. Deed restrictions, covenants running with the land, or other similar mechanisms may be used as the mechanism to impose a resale strategy. The Recipient shall report to the CDFI Fund the event of resale and/or recoupment and redeployment of the CMF Award, or an equivalent amount, in the manner described in the Assistance Agreement. The affordability restrictions may terminate upon occurrence of any of the following termination events: Foreclosure, transfer in lieu of foreclosure, or assignment of an FHA-insured mortgage to HUD. The Recipient may use purchase options, rights of first refusal or other preemptive rights to purchase the Housing before foreclosure to preserve affordability. The affordability restrictions shall be revived according to the original terms if, during the original affordability period, the owner of record before the termination event, obtains an ownership interest in the Housing. If there is a sale of Single-family housing funded by a CMF Award prior to the completion of the 10-year affordability period, the Recipient must demonstrate that it placed into service Single-family housing targeting the same income population (i.e., Extremely Low-Income, Very Low-Income, Low-Income) as the original Single-family housing, as set forth in the Assistance Agreement, financed with an equivalent amount to the recouped portion of the CMF Award, that will be tracked for the duration of the affordability period of the original Single-family housing.

(b) Rehabilitation not involving Purchase. Single-family housing that is currently owned by a qualifying Family, as set forth in § 1807.400, qualifies as Affordable Housing if it meets the requirements of this paragraph (b).

(1) The estimated value of the Single-family housing, after Rehabilitation, does not exceed 95 percent of the median purchase price for the area, as used in the HOME Program and as determined by the applicable Participating Jurisdiction; or

(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) Ownership interest. The ownership in the Single-family housing assisted under this section must meet the definition of Homeownership as defined in § 1807.104.

(d) New construction without Purchase. Newly constructed Single-family housing that is built on property currently owned by a Family that will occupy the Single-family housing upon completion, qualifies as Affordable Housing if it meets the requirements under paragraph (a) of this section.

(e) Converting rental units to Homeownership units for existing tenants. CMF-financed rental units may be converted to Homeownership units by selling, donating, or otherwise conveying the units to the existing tenants to enable the tenants to become homeowners in accordance with the requirements of this section. The Homeownership units are subject to a minimum period of affordability equal to the remaining affordability period.

Subpart E—Leveraged Costs; Eligible Project Costs; Commitment Requirements
§ 1807.500 Leveraged Costs; Eligible Project Costs.

(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) Leveraged Costs. (1) The applicable NOFA and/or the Assistance Agreement may set forth a required percentage of Leveraged Costs that must be funded by non-governmental sources.

(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.

§ 1807.501 Commitments; Payments.

(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.

§ 1807.502 CMF Award limits.

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.

§ 1807.503 Project Completion; Property standards.

(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) Accessibility. The Project must meet all applicable accessibility requirements set forth at 24 CFR part 8, which implements section 504 of the Rehabilitation Act of 1973 (29 U.S.C. 794), and Titles II and III of the Americans with Disabilities Act (42 U.S.C. 12131-12189) implemented at 28 CFR parts 35 and 36, as applicable. Multi-family housing, as defined in 24 CFR 100.201, must also meet all applicable design and construction requirements set forth in 24 CFR 100.205, which implements the Fair Housing Act (42 U.S.C. 3601-3619).

(ii) Disaster mitigation. The Project must meet all applicable State and local codes, ordinances, or other disaster mitigation requirements (e.g., earthquake, hurricanes, flooding, wild fires), or other requirements as the Department of Housing and Urban Development has established in 24 CFR part 93.

(iii) Lead-based paint. The Project must meet all applicable lead-based paint requirements, including those set forth in 24 CFR part 35.

(3) Rehabilitation standards. In addition, all Rehabilitation that is financed with a CMF Award must meet the following requirements:

(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 (e.g., windows, doors, siding, gutters); plumbing; electrical; heating, ventilation, and air conditioning.

(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) Manufactured housing. Construction of all manufactured housing must meet the Manufactured Home Construction and Safety Standards set forth in 24 CFR part 3280. These standards preempt State and local laws or codes, which are not identical to the Federal standards for the new construction of manufactured housing. The installation of all manufactured housing units must comply with applicable State and local laws or codes. In the absence of such laws or codes, the installation must comply with the manufacturer's written instructions for installation of manufactured housing units. Manufactured housing that is rehabilitated using a CMF Award must meet the requirements set out in paragraph (b)(1) of this section.

Subpart F—Tracking Funds; Uniform Administrative Requirements; Nature of Funds
§ 1807.600 Tracking funds.

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.

§ 1807.601 Uniform Administrative Requirements.

The Uniform Administrative Requirements apply to all CMF Awards.

§ 1807.602 Nature of funds.

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.

Subpart G—Notice of Funds Availability; Applications
§ 1807.700 Notice of funds availability.

Each Applicant must submit a CMF Award application in accordance with the applicable Notice of Funds Availability (NOFA) published in the Federal Register. The NOFA will advise prospective Applicants on how to obtain and complete an application and will establish deadlines and other requirements. The NOFA will specify application evaluation factors and any limitations, special rules, procedures, and restrictions for a particular application round. After receipt of an application, the CDFI Fund may request clarifying or technical information on the materials submitted as part of the application.

Subpart H—Evaluation and Selection of Applications
§ 1807.800 Evaluation and selection—general.

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.

§ 1807.801 Evaluation of applications.

(a) Eligibility and completeness. An Applicant will not be eligible to receive a CMF Award if it fails to meet the eligibility requirements described in § 1807.200 and in the applicable NOFA, or if the Applicant has not submitted complete application materials. For the purposes of this paragraph (a), the CDFI Fund reserves the right to request additional information from the Applicant, if the CDFI Fund deems it appropriate.

(b) Substantive review. In evaluating and selecting applications to receive assistance, the CDFI Fund will evaluate the Applicant's likelihood of success in meeting the factors set forth in the applicable NOFA including, but not limited to:

(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) Consultation with appropriate regulatory agencies. In the case of an Applicant that is a Federally regulated financial institution, the CDFI Fund may consult with the Appropriate Federal Banking Agency or Appropriate State Agency prior to making a final award decision and prior to entering into an Assistance Agreement.

(e) Recipient selection. The CDFI Fund will select Recipients based on the criteria described in paragraph (b) of this section and any other criteria set forth in this part or the applicable NOFA.

Subpart I—Terms and Conditions of CMF Award
§ 1807.900 Assistance agreement.

(a) Each Applicant that is selected to receive a CMF Award must enter into an Assistance Agreement with the CDFI Fund. The Assistance Agreement will set forth certain required terms and conditions for the CMF Award that may include, but are not limited to, the following:

(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.

§ 1807.901 Payment of funds.

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.

§ 1807.902 Data collection and reporting.

(a) Data; General. The Recipient must maintain such records as may be prescribed by the CDFI Fund that are necessary to:

(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) Customer profiles. The Recipient must compile such data on the gender, race, ethnicity, national origin, or other information on individuals that are benefiting from the CMF Award, as the CDFI Fund shall prescribe in the Assistance Agreement. Such data will be used to determine whether residents of the Recipient's Service Area are adequately served and to evaluate the impact of the CMF Award.

(c) Access to records. The Recipient must submit such financial and activity reports, records, statements, and documents at such times, in such forms, and accompanied by such reporting data, as required by the CDFI Fund or the U.S. Department of the Treasury to ensure compliance with the requirements of this part and to evaluate the impact of the CMF Award. The United States Government, including the U.S. Department of the Treasury, the Comptroller General, and their duly authorized representatives, shall have full and free access to the Recipient's offices and facilities and all books, documents, records, and financial statements relating to use of Federal funds and may copy such documents as they deem appropriate and audit or provide for an audit at least annually. The CDFI Fund, if it deems appropriate, may prescribe access to record requirements for entities that receive a CMF Award from the Recipient.

(d) Retention of records. The Recipient shall comply with all applicable record retention requirements set forth in the Uniform Administrative Requirements (as applicable) and the Assistance Agreement.

(e) Data collection and reporting—(1) Financial reporting, (i) All Nonprofit Organization Recipients that are required to have their financial statements audited pursuant to the Uniform Administrative Requirements, must submit their single-audits by a time set forth in the applicable NOFA or Assistance Agreement. Nonprofit Organization Recipients (excluding Insured CDFIs and State-Insured Credit Unions) that are not required to have financial statements audited pursuant to the Uniform Administrative Requirements, must submit to the CDFI Fund a statement signed by the Recipient's authorized representative or certified public accountant, asserting that the Recipient is not required to have a single-audit pursuant to the Uniform Administrative Requirements as indicated in the Assistance Agreement. In such instances, the CDFI Fund may require additional audits to be performed and/or submitted to the CDFI Fund as stated in the applicable Notice of Funds Availability and Assistance Agreement.

(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) Annual report. (i) The Recipient shall submit a performance and financial report that shall be specified in the Assistance Agreement (annual report). The annual report consists of several components which may include, but are not limited to, a report on performance goals and measures, explanation of any Recipient noncompliance, and such other information as may be required by the CDFI Fund. The annual report components shall be specified and described in the Assistance Agreement.

(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 Appropriate State Agency, as the case may be.

(f) Public access. The CDFI Fund shall make reports described in this section available for public inspection after deleting or redacting any materials necessary to protect privacy or proprietary interests.

§ 1807.903 Compliance with government requirements.

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.

§ 1807.904 Lobbying restrictions.

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.

§ 1807.905 Criminal provisions.

The criminal provisions of 18 U.S.C. 657 regarding embezzlement or misappropriation of funds are applicable to all Recipients and insiders.

§ 1807.906 CDFI Fund deemed not to control.

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.

§ 1807.907 Limitation on liability.

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.

§ 1807.908 Fraud, waste and abuse.

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.

Mary Ann Donovan, Director, Community Development Financial Institutions Fund.
[FR Doc. 2016-02132 Filed 2-3-16; 4:15 pm] BILLING CODE 4810-70-P
DEPARTMENT OF TRANSPORTATION Federal Aviation Administration 14 CFR Part 71 [Docket No. FAA-2015-7483; Airspace Docket No. 15-AGL-23] Amendment of Class E Airspace for the Following Michigan Towns: Alpena, MI; and Muskegon, MI AGENCY:

Federal Aviation Administration (FAA), DOT.

ACTION:

Final rule.

SUMMARY:

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.

DATES:

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.

ADDRESSES:

FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at http://www.faa.gov/air_traffic/publications/. For further information, you can contact the Airspace Policy Group, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC 29591; telephone: 202-267-8783. The Order is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of FAA Order 7400.9Z at NARA, call 202-741-6030, or go to http://www.archives.gov/federal_register/code_of_federal-regulations/ibr_locations.html.

FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.

FOR FURTHER INFORMATION CONTACT:

Jeffrey Claypool, Federal Aviation Administration, Operations Support Group, Central Service Center, 10101 Hillwood Parkway, Fort Worth, TX 76177; telephone (817) 222-5711.

SUPPLEMENTARY INFORMATION: Authority for This Rulemaking

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.

History

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.

Availability and Summary of Documents for Incorporation by Reference

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 ADDRESSES section of this document. FAA Order 7400.9Z lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

The Rule

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.

Regulatory Notices and Analyses

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.

Environmental Review

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.

Lists of Subjects in 14 CFR Part 71

Airspace, Incorporation by reference, Navigation (air).

Adoption of the Amendment

In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:

PART 71—DESIGNATION OF CLASS A, B, C, D, AND E AIRSPACE AREAS; AIR TRAFFIC SERVICE ROUTES; AND REPORTING POINTS 1. The authority citation for part 71 continues to read as follows: Authority:

49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.

§ 71.1 [Amended]
2. The incorporation by reference in 14 CFR 71.1 of FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, effective September 15, 2015, is amended as follows: Paragraph 6002 Class E Airspace Designated as Surface Areas. AGL MI E2 Alpena, MI (Amended) Alpena County Regional Airport (Lat. 45°04′41″ N., long. 83°33′37″ W.) Alpena VORTAC (Lat. 45°04′58″ N., long. 83°33′25″ W.)

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.

AGL MI E2 Muskegon, MI (Amended) Muskegon County Airport, MI (Lat. 43°10′04″ N., long. 086°14′08″ W.)

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.

Paragraph 6004 Class E Airspace Areas Designated as an Extension to a Class D or Class E Surface Area. AGL MI E4 Alpena, MI (Amended) Alpena County Regional Airport, MI (Lat. 45°04′41″ N., long. 83°33′37″ W.) Alpena VORTAC (Lat. 45°04′58″ N., long. 83°33′25″ W.)

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.

AGL MI E4 Muskegon, MI (Amended) Muskegon County Airport, MI (Lat. 43°10′04″ N., long. 086°14′08″ W.) Muskegon VORTAC (Lat. 43°10′09″ N., long. 086°02′22″ W.)

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.

Issued in Fort Worth, Texas, on January 27, 2016. Robert W. Beck, Manager, Operations Support Group, ATO Central Service Center.
[FR Doc. 2016-02285 Filed 2-5-16; 8:45 am] BILLING CODE 4910-13-P
DEPARTMENT OF TRANSPORTATION Federal Aviation Administration 14 CFR Part 71 [Docket No. FAA-2015-7484; Airspace Docket No. 15-AGL-24] Amendment of Class E Airspace for the Following Minnesota Towns: Rochester, MN; and St. Cloud, MN AGENCY:

Federal Aviation Administration (FAA), DOT.

ACTION:

Final rule.

SUMMARY:

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.

DATES:

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.

ADDRESSES:

FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at http://www.faa.gov/air_traffic/publications/. For further information, you can contact the Airspace Policy Group, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC, 29591; telephone: 202-267-8783. The Order is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of FAA Order 7400.9Z at NARA, call 202-741-6030, or go to http://www.archives.gov/federal_register/code_of_federal-regulations/ibr_locations.html.

FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.

FOR FURTHER INFORMATION CONTACT:

Jeffrey Claypool, Federal Aviation Administration, Operations Support Group, Central Service Center, 10101 Hillwood Parkway, Fort Worth, TX 76177; telephone (817) 222-5711.

SUPPLEMENTARY INFORMATION: Authority for This Rulemaking

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.

History

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.

Availability and Summary of Documents for Incorporation by Reference

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 ADDRESSES section of this document. FAA Order 7400.9Z lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

The Rule

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.

Regulatory Notices and Analyses

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.

Environmental Review

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.

Lists of Subjects in 14 CFR Part 71

Airspace, Incorporation by reference, Navigation (air).

Adoption of the Amendment

In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:

PART 71—DESIGNATION OF CLASS A, B, C, D, AND E AIRSPACE AREAS; AIR TRAFFIC SERVICE ROUTES; AND REPORTING POINTS 1. The authority citation for part 71 continues to read as follows: Authority:

49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.

§ 71.1 [Amended]
2. The incorporation by reference in 14 CFR 71.1 of FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, effective September 15, 2015, is amended as follows: Paragraph 6002 Class E Airspace Designated as Surface Areas. AGL MN E2 Rochester, MN (Amended) Rochester International Airport, MN (Lat. 43°54′30″ N., long. 92°30′00″ W.) Rochester VOR/DME (Lat. 43°46′58″ N., long. 92°35′49″ W.)

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.

AGL MN E2 St. Cloud, MN (Amended) St. Cloud Regional Airport, MN (Lat. 45°32′48″ N., long. 94°03′36″ W.) St. Cloud VOR/DME (Lat. 45°32′58″ N., long. 94°03′31″ W.)

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.

Paragraph 6004 Class E Airspace Areas Designated as an Extension to a Class D or Class E Surface Area. AGL MN E4 Rochester, MN (Amended) Rochester International Airport, MN (Lat. 43°54′30″ N., long. 92°30′00″ W.) Rochester VOR/DME (Lat. 43°46′58″ N., long. 92°35′49″ W.)

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.

AGL MN E4 St. Cloud, MN (Amended) St. Cloud Regional Airport, MN (Lat. 45°32′48″ N., long. 94°03′36″ W.) St. Cloud VOR/DME (Lat. 45°32′58″ N., long. 94°03′31″ W.)

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.

Issued in Fort Worth, Texas, on January 27, 2016. Robert W. Beck, Manager, Operations Support Group, ATO Central Service Center.
[FR Doc. 2016-02283 Filed 2-5-16; 8:45 am] BILLING CODE 4910-13-P
DEPARTMENT OF TRANSPORTATION Federal Aviation Administration 14 CFR Part 71 [Docket No. FAA-2015-7486; Airspace Docket No. 15-AGL-26] Amendment of Class E Airspace; Wilmington, OH AGENCY:

Federal Aviation Administration (FAA), DOT.

ACTION:

Final rule.

SUMMARY:

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.

DATES:

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.

ADDRESSES:

FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at http://www.faa.gov/air_traffic/publications/. For further information, you can contact the Airspace Policy Group, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC 29591; telephone: 202-267-8783. The Order is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of FAA Order 7400.9Z at NARA, call 202-741-6030, or go to http://www.archives.gov/federal_register/code_of_federal-regulations/ibr_locations.html.

FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.

FOR FURTHER INFORMATION CONTACT:

Jeffrey Claypool, Federal Aviation Administration, Operations Support Group, Central Service Center, 10101 Hillwood Parkway, Fort Worth, TX 76177; telephone (817) 222-5711.

SUPPLEMENTARY INFORMATION:

Authority for This Rulemaking

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.

History

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.

Availability and Summary of Documents for Incorporation by Reference

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 ADDRESSES section of this document. FAA Order 7400.9Z lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

The Rule

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.

Regulatory Notices and Analyses

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.

Environmental Review

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.

Lists of Subjects in 14 CFR Part 71

Airspace, Incorporation by reference, Navigation (air).

Adoption of the Amendment

In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:

PART 71—DESIGNATION OF CLASS A, B, C, D, AND E AIRSPACE AREAS; AIR TRAFFIC SERVICE ROUTES; AND REPORTING POINTS 1. The authority citation for part 71 continues to read as follows: Authority:

49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.

§ 71.1 [Amended]
2. The incorporation by reference in 14 CFR 71.1 of FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, effective September 15, 2015, is amended as follows: Paragraph 6002 Class E Airspace Designated as Surface Areas. AGL OH E2 Wilmington, OH (Amended) Wilmington, Wilmington Air Park, OH (Lat. 39°25′41″ N., long. 083°47′32″ W.) Wilmington, Hollister Field Airport, OH (Lat. 39°26′15″ N., long. 083°42′30″ W.)

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.

Paragraph 6004 Class E Airspace Areas Designated as an Extension to a Class D or Class E Surface Area. AGL OH E4 Wilmington, OH (Amended) Wilmington, Wilmington Air Park, OH (Lat. 39°25′41″ N., long. 083°47′32″ W.) Wilmington, Hollister Field Airport, OH (Lat. 39°26′15″ N., long. 083°42′30″ W.) Midwest VOR/DME (Lat. 39°25′47″ N., long. 083°48′04″ W.)

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.

Issued in Fort Worth, Texas, on January 29, 2016. Robert W. Beck, Manager, Operations Support Group, ATO Central Service Center.
[FR Doc. 2016-02284 Filed 2-5-16; 8:45 am] BILLING CODE 4910-13-P
DEPARTMENT OF JUSTICE Drug Enforcement Administration 21 CFR Part 1308 [Docket No. DEA-367] RIN 1117-AB39 Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products: Vicks® VapoInhaler® AGENCY:

Drug Enforcement Administration, Department of Justice.

ACTION:

Final rule.

SUMMARY:

This final rule adopts the interim final rule, with a correction to spelling of the manufacturer's name that was published in the Federal Register on October 27, 2015. The Drug Enforcement Administration is amending the table of Excluded Nonnarcotic Products to update the listing for Vicks® VapoInhaler®, containing 50 mg levmetamfetamine in a nasal decongestant inhaler, marketed by The Procter & Gamble Company. This over-the-counter, non-narcotic drug product is excluded from provisions of the Controlled Substances Act.

DATES:

This final rule is effective on February 8, 2016.

FOR FURTHER INFORMATION CONTACT:

Barbara J. Boockholdt, Office of Diversion Control, Drug Enforcement Administration; Mailing Address: 8701 Morrissette Drive, Springfield, Virginia 22152; Telephone: (202) 598-6812.

SUPPLEMENTARY INFORMATION:

Legal Authority

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 et seq., be lawfully sold over-the-counter without a prescription. 21 U.S.C. 811(g)(1). Such exclusions apply only to specific nonnarcotic drugs following suitable application to the DEA in accordance with 21 CFR 1308.21. The current table of Excluded Nonnarcotic Products is found in 21 CFR 1308.22. The authority to exclude such substances has been delegated to the Administrator of the DEA, 28 CFR 0.100, and redelegated to the Deputy Assistant Administrator of the Office of Diversion Control, section 7 of 28 CFR part 0, appendix to subpart R.

Background

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 Federal Register on October 27, 2015. 80 FR 65635. The correct spelling of the manufacturer's name is “The Procter & Gamble Company.” The interim final rule contained a typographical error in which “Procter” was inadvertently spelled as “Proctor.”

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 l-desoxyephedrine (levmetamfetamine) from 113 mg to 50 mg in their Vicks® InhalerTM product which is currently excluded under § 1308.22. Levmetamfetamine is controlled in schedule II as an isomer of methamphetamine. 21 CFR 1308.12(d)(2). P&G requested that the DEA update the current exclusion for its Vicks® InhalerTM and indicated it had acquired Richardson-Vicks, Inc. (including its subsidiary, the Vick Chemical Company). The company stated that the product name has been modified from Vicks® InhalerTM to Vicks® VapoInhaler® and that the change included a corresponding National Drug Code (NDC) number reassignment by the U.S. Food and Drug Administration. Furthermore, P&G stated that the nomenclature for the active ingredient/controlled substance had been changed from l-desoxyephedrine to levmetamfetamine. P&G indicated that nothing in the formulation change affects other aspects of the drug delivery system.

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.

Regulatory Analyses Executive Orders 12866 and 13563

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.

Regulatory Flexibility Analysis

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.

Executive Order 12988

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.

Executive Order 13132

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.

Executive Order 13175

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.

Unfunded Mandates Reform Act of 1995

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 et seq., that this action would not result in any Federal mandate that may result “in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100,000,000 or more (adjusted for inflation) in any one year * * *.” Therefore, neither a Small Government Agency Plan nor any other action is required under provisions of the UMRA.

Paperwork Reduction Act

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.

Congressional Review Act

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.

List of Subjects in 21 CFR Part 1308

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 Federal Register on October 27, 2015 (80 FR 65635), is adopted as final with the following change:

PART 1308—SCHEDULES OF CONTROLLED SUBSTANCES 1. The authority citation for 21 CFR part 1308 continues to read as follows: Authority:

21 U.S.C. 811, 812, 871(b), unless otherwise noted.

2. Amend § 1308.22, in the table, by removing the company name, “Proctor & Gamble Co., The” and adding in its place “Procter & Gamble Co., The”. Dated: February 2, 2016. Louis J. Milione, Deputy Assistant Administrator, Office of Diversion Control.
[FR Doc. 2016-02403 Filed 2-5-16; 8:45 am] BILLING CODE 4410-09-P
DEPARTMENT OF JUSTICE Drug Enforcement Administration 21 CFR Part 1308 [Docket No. DEA-409] RIN 1117-ZA30 Schedules of Controlled Substances: Table of Excluded Nonnarcotic Products: Nasal Decongestant Inhaler/Vapor Inhaler AGENCY:

Drug Enforcement Administration, Department of Justice.

ACTION:

Final rule.

SUMMARY:

This final rule adopts, without change, the interim final rule that was published in the Federal Register on October 27, 2015. The Drug Enforcement Administration is amending the table of Excluded Nonnarcotic Products to update the company name for the drug product Nasal Decongestant Inhaler/Vapor Inhaler (containing 50 milligrams levmetamfetamine) to Aphena Pharma Solutions—New York, LLC. This over-the-counter, nonnarcotic drug product is excluded from the provisions of the Controlled Substances Act.

DATES:

This final rule is effective on February 8, 2016.

FOR FURTHER INFORMATION CONTACT:

Barbara J. Boockholdt, Office of Diversion Control, Drug Enforcement Administration; Mailing Address: 8701 Morrissette Drive, Springfield, Virginia 22152; Telephone: (202) 598-6812.

SUPPLEMENTARY INFORMATION:

Legal Authority

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 et seq., be lawfully sold over-the-counter without a prescription. 21 U.S.C. 811(g)(1). Such exclusions apply only to specific nonnarcotic drugs following suitable application to the DEA in accordance with 21 CFR 1308.21. The current table of Excluded Nonnarcotic Products is found in 21 CFR 1308.22. The authority to exclude such substances has been delegated to the Administrator of the DEA, 28 CFR 0.100, and redelegated to the Deputy Assistant Administrator of the Office of Diversion Control, section 7 of 28 CFR part 0, appendix to subpart R.

Background

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 Federal Register on October 27, 2015. 80 FR 65632.

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 (i.e., facility) and the formulation for the drug product Nasal Decongestant Inhaler/Vapor Inhaler had not changed.

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 1 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 drug product continues to meet the criteria for exclusion from the CSA pursuant to 21 U.S.C. 811(g)(1).

1 Levmetamfetamine is controlled in schedule II of the CSA because it is an isomer of methamphetamine.

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 voicing support for the action. The DEA appreciates the support for the 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 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.

Regulatory Analyses Executive Orders 12866 and 13563

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.

Regulatory Flexibility Analysis

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.

Executive Order 12988

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.

Executive Order 13132

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.

Executive Order 13175

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.

Unfunded Mandates Reform Act of 1995

The DEA has determined and certifies pursuant to the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1501 et seq., that this action would not result in any Federal mandate that may result “in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100,000,000 or more (adjusted for inflation) in any one year * * *.” Therefore, neither a Small Government Agency Plan nor any other action is required under provisions of the UMRA.

Paperwork Reduction Act

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.

Congressional Review Act

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.

List of Subjects in 21 CFR Part 1308

Administrative practice and procedure, Drug traffic control, Reporting and recordkeeping requirements.

PART 1308—SCHEDULES OF CONTROLLED SUBSTANCES

Accordingly, for the reasons stated above, the interim final rule that was published in the Federal Register on October 27, 2015 (80 FR 65632), is adopted as a final rule without change.

Dated: February 2, 2016. Louis J. Milione, Deputy Assistant Administrator, Office of Diversion Control.
[FR Doc. 2016-02404 Filed 2-5-16; 8:45 am] BILLING CODE 4410-09-P
DEPARTMENT OF TRANSPORTATION National Highway Traffic Safety Administration 49 CFR Part 571 [Docket No. NHTSA-2014-0073] RIN 2127-AL27 Federal Motor Vehicle Safety Standards; Lamps, Reflective Devices, and Associated Equipment AGENCY:

National Highway Traffic Safety Administration (NHTSA), Department of Transportation (DOT).

ACTION:

Final rule.

SUMMARY:

NHTSA is amending the side marker requirements contained in the Federal Motor Vehicle Safety Standard (FMVSS) on lamps, reflective devices and associated equipment for vehicles 80 inches or more in width and less than 30 feet long. This final rule adopts the amendments proposed in the Notice of Proposed Rulemaking (NPRM), published on December 4, 2012. These amendments will restore the side marker photometry requirements for motor vehicles under thirty feet in length that were in place prior to the 2007 final rule that reorganized the standard. Restoration of the side marker requirements will have no negative impact on safety or function and will allow motor vehicle manufacturers to avoid unnecessary modifications to their side marker lamps with no added safety or functional benefit.

DATES:

Effective Date: August 8, 2016. Compliance Date: Optional early compliance as discussed below.

Petitions for Reconsideration: Petitions for reconsideration of this final rule must be received not later than March 24, 2016.

ADDRESSES:

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 FURTHER INFORMATION CONTACT:

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).

SUPPLEMENTARY INFORMATION:

I. Background

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 1967.1 The main purpose of side marker lamps is to indicate the overall length of the vehicle. The photometric requirements are meant to ensure that the side marker lamps are sufficiently visible from a range of viewing angles. This final rule addresses an unintentional change NHTSA made to the photometric requirements for side marker lamps when it reorganized FMVSS No. 108 in 2007.2 Before considering the changes made by this final rule, it is useful to briefly examine the evolution of the side marker requirements before 2007.

1See 32 FR 2408 (Feb. 3, 1967).

2 72 FR 68234 (Dec. 4, 2007). The reorganized standard did not take effect until December 1, 2012. 76 FR 48009 (Aug. 8, 2011).

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.3 At the time of the Chrysler petition, FMVSS No. 108 required that the photometric requirements for side marker lamps be met at test points 45 degrees outboard and inboard of the lateral center line passing through the lamps. FMVSS No. 108, however, permitted an additional compliance option for vehicles less than 80 inches in width. This additional compliance option had the effect of relaxing the inboard photometry requirements for the side marker lamps.4 Chrysler—which wanted to use a common side marker design for its single-wheeled (less than 80 inches wide) and its dual-wheeled (greater than 80 inches wide) pickup trucks—petitioned to make this compliance option available to all vehicles regardless of width. NHTSA agreed with Chrysler that eligibility for the additional compliance option should not depend on a vehicle's width, but did not agree that it should be available to all vehicles. The agency explained that the additional compliance option would not be appropriate for vehicles that are 30 feet or longer.5 Accordingly, the 1980 final rule revised FMVSS No. 108 by deleting the words “80 inches in overall width” and substituting “30 feet in overall length.”

3 45 FR 45287 (July 3, 1980).

4 Specifically, under this additional compliance option, the photometric requirements could be met for all inboard test points at a distance of 15 feet from the vehicle and 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. This results in an angle of less than 45 degrees instead of the fixed 45 degrees that was otherwise required, so that the side marker lamp was effectively permitted to illuminate a smaller area than it otherwise would have been required to illuminate. See 45 FR 45287 (July 3, 1980) (citing 49 CFR 571.108, S4.1.1.8).

5 This is because testing of side marker lamps is done at a distance of 15 feet perpendicular to the vehicle and at a 45 degree angle. At such a distance and angle, only a vehicle 30 feet long or under would have both of its side marker lamps visible.

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 6 standards, incorporated by reference. Prior to the reorganization, FMVSS No. 108 would, in many instances, specify requirements by simply referencing an SAE standard (which contained the requirements), instead of explicitly specifying those requirements in the text of FMVSS No. 108. However, when the standard was reorganized in 2007, requirements contained in the referenced third-party standards were included directly in the regulatory text, instead of incorporating the requirements by referencing the standard that contained those requirements. The agency explained that the reorganization was administrative in nature and that the FMVSS No. 108 requirements were not being increased, decreased, or substantively modified.

6 The Society of Automotive Engineers (now SAE International). SAE is an organization that develops technical standards based on best practices.

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) (i.e., the requirements were specified using incorporation by reference). In addition, the pre-reorganization regulatory text also explicitly specified the alternative compliance option that was the subject of the 1980 final rule.7 The side marker lamp requirements specified in SAE J592e (July 1972) also included (in a footnote) an alternative compliance option for vehicles less than 80 inches wide. This was the same compliance option for which the agency had deleted the words “80 inches in overall width” and added the words “30 feet in overall length” in the 1980 final rule. When NHTSA reorganized FMVSS No. 108 in 2007, the requirements contained in SAE Standard J592e (July 1972) were included directly into the regulatory text of FMVSS No. 108, thus eliminating the incorporation by reference; 8 this included the width-based compliance option that we had deleted from FMVSS No. 108 in 1980. Accordingly, the 2007 reorganization specified the alternative compliance option that for each motor vehicle less than 30 feet in overall length and less than 2032 mm [80 inches] in overall width, the minimum photometric intensity requirements for a side marker lamp may be met for all inboard test points at a distance of 15 feet from the vehicle and 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.9

7 The 1980 final rule placed this requirement in S4.1.1.8. Due to subsequent amendments, at the time of the 2007 reorganization, the requirement was in S5.1.1.8.

8 The requirements were placed in a new table, Table X.

9 See S7.4.13.2.

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 and less than 80 inches wide. The agency did not cite within its analysis in the 2007 final rule the 1980 rulemaking that replaced the width criterion with the length criterion.10

10 The agency did receive comments to the NPRM to reorganize FMVSS No. 108 that stated that the agency's proposal to add the width criterion to the side marker requirements was a substantive change to the side marker requirements. However, these comments did not cite the 1980 rulemaking that had deleted the width criterion.

II. 2012 Side Marker NPRM

To address this change, NHTSA published a notice of proposed rulemaking (NPRM) on December 4, 2012.11 As we explained in the NPRM, based on our communications with vehicle manufacturers, a petition for rulemaking from the Alliance for Automobile Manufacturers, and our review of the 1980 final rule, NHTSA recognized that the 2007 rewrite erroneously added the width requirement back into the standard. This inadvertent change might have required manufacturers to perform costly redesigns in order to comply with the 2007 final rule. Accordingly, the NPRM proposed to restore the pre-reorganization side marker requirements for vehicles that are 80 inches or more in width and less than 30 feet long. Considering the cost manufacturers would have to incur as a result of the modifications in the 2007 final rule, NHTSA announced in the 2012 NPRM that it would not pursue compliance actions against manufacturers that install side marker lamps on vehicles that are 80 inches or more in width and less than 30 feet long that fail to meet the 45 degree inboard photometric requirements of the 2007 final rule, provided that they meet the photometric requirements at a distance of 15 feet from the vehicle and 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. NHTSA stated that this enforcement policy would be effective until the rulemaking was completed. That enforcement policy will end as of the effective date of this final rule.

11 77 FR 71752, Dec. 4, 2012.

III. Comments on the NPRM

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.

IV. Agency Comment Analysis and Agency Decision

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.

V. Effective Date

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.

VI. Regulatory Notices and Analyses A. Executive Order 12866, Executive Order 13563, and DOT Regulatory Policies and Procedures

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 final rule allows manufacturers to avoid the cost of redesigning the side marker lamps for dual-wheeled pickup trucks because these vehicles can now continue to meet the side marker photometry requirements for narrower vehicles. Because there are not any costs associated with this rulemaking and only minor benefits, we have not prepared a separate economic analysis for this rulemaking.

B. Executive Order 13609: Promoting International Regulatory Cooperation

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.

C. Regulatory Flexibility Act

In compliance with the Regulatory Flexibility Act, 5 U.S.C. 60l et seq., NHTSA has evaluated the effects of this action on small entities. I hereby certify that this rule would not have a significant impact on a substantial number of small entities. The final rule would affect manufacturers of motor vehicle light equipment, but the entities that qualify as small businesses would not be significantly affected by this rulemaking because the agency is restoring requirements that previously existed in an older version of the regulation. This rulemaking is not expected to affect the cost of manufacturing motor vehicle lighting equipment.

D. Executive Order 13132

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. See Geier v. American Honda Motor Co., 529 U.S. 861 (2000).

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 (e.g., the language and structure of the regulatory text) and objectives of this rule and finds that this rule, like many NHTSA rules, prescribes only a minimum safety standard. As such, NHTSA does not intend that this rule preempt state tort law that would effectively impose a higher standard on motor vehicle manufacturers than that established by this rule. Establishment of a higher standard by means of State tort law would not conflict with the minimum standard announced here. Without any conflict, there could not be any implied preemption of a State common law tort cause of action.

E. National Environmental Policy Act

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.

F. Paperwork Reduction Act

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.

G. National Technology Transfer and Advancement Act

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.

H. Civil Justice Reform

With respect to the review of the promulgation of a new regulation, section 3(b) of Executive Order 12988, “Civil Justice Reform” (61 FR 4729, February 7, 1996) requires that Executive agencies make every reasonable effort to ensure that the regulation: (1) Clearly specifies the preemptive effect; (2) clearly specifies the effect on existing Federal law or regulation; (3) provides a clear legal standard for affected conduct, while promoting simplification and burden reduction; (4) clearly specifies the retroactive effect, if any; (5) specifies whether administrative proceedings are to be required before parties file suit in court; (6) adequately defines key terms; and (7) addresses other important issues affecting clarity and general draftsmanship under any guidelines issued by the Attorney General. This document is consistent with these requirements.

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.

I. Unfunded Mandates Reform Act

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.

J. Executive Order 13211

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.

K. Regulation Identifier Number (RIN)

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.

L. Privacy Act

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 Federal Register published on April 11, 2000 (Volume 65, Number 70; Pages 19477-78).

Regulatory Text List of Subjects in 49 CFR Part 571

Imports, Motor vehicle safety, Motor vehicles, Tires.

In consideration of the foregoing, NHTSA is amending 49 CFR part 571 as set forth below.

PART 571—FEDERAL MOTOR VEHICLE SAFETY STANDARDS 1. The authority citation for part 571 continues to read as follows: Authority:

49 U.S.C. 322, 30111, 30115, 30117, 30166: delegation of authority at 49 CFR 1.95.

2. Section 571.108 is amended by revising paragraph S7.4.13.2 and footnote 1 of Table X to read as follows:
§ 571.108 Standard No. 108; Lamps, reflective devices, and associated equipment.

S7.4.13.2 Inboard photometry. For each motor vehicle less than 30 feet in overall length, the minimum photometric intensity requirements for a side marker lamp may be met for all inboard test points at a distance of 15 feet from the vehicle and 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.

Table X—Side Marker Lamp Photometry Requirements

(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.

Issued in Washington, DC, on February 1, 2016 under authority delegated in 49 CFR 1.95. Mark R. Rosekind, Administrator.
[FR Doc. 2016-02268 Filed 2-5-16; 8:45 am] BILLING CODE 4910-59-P
NATIONAL TRANSPORTATION SAFETY BOARD 49 CFR Part 830 [Docket No. NTSB-AS-2012-0001] RIN 3147-AA11 Notification and Reporting of Aircraft Accidents or Incidents and Overdue Aircraft, and Preservation of Aircraft Wreckage, Mail, Cargo, and Records AGENCY:

National Transportation Safety Board (NTSB).

ACTION:

Final rule; confirmation of effective date.

SUMMARY:

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.

DATES:

The final rule published December 15, 2015 (80 FR 77586) becomes effective February 16, 2016.

ADDRESSES:

A copy of this final rule, published in the Federal Register, is available for inspection and copying in the NTSB's public reading room, located at 490 L'Enfant Plaza SW., Washington, DC 20594-2000. Alternatively, a copy of the rule is available on the NTSB Web site, at http://www.ntsb.gov, and at the government-wide Web site on regulations, at http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT:

Scott Dunham, National Resource Specialist—ATC, Office of Aviation Safety, (202) 314-6387.

SUPPLEMENTARY INFORMATION:

As described in the NTSB's preamble summarizing the direct final rule, in 2010, the NTSB added a requirement for notification of reports of Airborne Collision Avoidance System (ACAS) resolution advisories issued either (i) when an aircraft is being operated on an instrument flight rules (IFR) flight plan and compliance with the advisory is necessary to avert a substantial risk of collision between two or more aircraft, or (ii) to an aircraft operating in class A airspace. 75 FR 922 (Jan. 7, 2010).

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 www.ntsb.gov or the NTSB Response Operations Center at 844-373-9922 or 202-314-6290, should the operators need to contact the NTSB to inform the agency of an accident or incident. This document confirms both the change to section 830.5(a)(10) and the updated text of the footnote.

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. Id. § 800.44(d). Section 800.44 also defines “adverse comment” for purposes of the direct final rulemaking procedure. Comments on the NTSB's change to section 830.5(a)(10) and the updated footnote accompanying section 830.5 were due by January 14, 2016. The NTSB did not receive any comments. Therefore, as indicated in the direct final rule, the changes will become effective on February 16, 2016.

Legal Analyses and Effective Date

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 et seq.) requires each agency to review its rulemaking to assess the potential impact on small entities, unless the agency determines a rule is not expected to have a significant economic impact on a substantial number of small entities. The NTSB certifies this final rule will not have a significant economic impact on a substantial number of small entities.

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.

List of Subjects in 49 CFR Part 830

Aircraft accidents, Aircraft incidents, Aviation safety, Overdue aircraft notification and reporting, Reporting and recordkeeping requirements.

Dated: February 3, 2016. Christopher A. Hart, Chairman.
[FR Doc. 2016-02413 Filed 2-5-16; 8:45 am] BILLING CODE 7533-01-P
DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration 50 CFR Part 679 [Docket No. 141021887-5172-02] RIN 0648-XE429 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 AGENCY:

National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

ACTION:

Temporary rule; closure.

SUMMARY:

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.

DATES:

Effective 1200 hrs, Alaska local time (A.l.t.), February 3, 2016, though 2400 hrs, A.l.t., December 31, 2016.

FOR FURTHER INFORMATION CONTACT:

Steve Whitney, 907-586-7269.

SUPPLEMENTARY INFORMATION:

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 2016 harvest specifications for groundfish in the BSAI (80 FR 11919, March 5, 2015).

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.

Classification

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.

Authority:

16 U.S.C. 1801 et seq.

Dated: February 3, 2016. Emily H. Menashes, Acting Director, Office of Sustainable Fisheries, National Marine Fisheries Service.
[FR Doc. 2016-02391 Filed 2-3-16; 4:15 pm] BILLING CODE 3510-22-P
DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration 50 CFR Part 679 [Docket No. 140918791-4999-02] RIN 0648-XE426 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 AGENCY:

National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

ACTION:

Temporary rule; modification of a closure.

SUMMARY:

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.

DATES:

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.

ADDRESSES:

You may submit comments on this document, identified by NOAA-NMFS-2014-0118, by any of the following methods:

Electronic Submission: Submit all electronic public comments via the Federal e-Rulemaking Portal. Go to www.regulations.gov/#!docketDetail;D=NOAA-NMFS-2014-0118, click the “Comment Now!” icon, complete the required fields, and enter or attach your comments.

Mail: Submit written comments to Glenn Merrill, Assistant Regional Administrator, Sustainable Fisheries Division, Alaska Region NMFS, Attn: Ellen Sebastian. Mail comments to P.O. Box 21668, Juneau, AK 99802-1668.

Instructions: Comments sent by any other method, to any other address or individual, or received after the end of the comment period, may not be considered by NMFS. All comments received are a part of the public record and will generally be posted for public viewing on www.regulations.gov without change. All personal identifying information (e.g., name, address), confidential business information, or otherwise sensitive information submitted voluntarily by the sender will be publicly accessible. NMFS will accept anonymous comments (enter “N/A” in the required fields if you wish to remain anonymous). Attachments to electronic comments will be accepted in Microsoft Word, Excel, or Adobe PDF file formats only.

FOR FURTHER INFORMATION CONTACT:

Obren Davis, 907-586-7228.

SUPPLEMENTARY INFORMATION:

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.

Classification

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 opening of directed fishing for Pacific cod by catcher/processors using trawl gear in the Western Regulatory Area of the GOA. 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.

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.

Authority:

16 U.S.C. 1801 et seq.

Dated: February 3, 2016. Emily H. Menashes, Acting Director, Office of Sustainable Fisheries, National Marine Fisheries Service.
[FR Doc. 2016-02394 Filed 2-3-16; 4:15 pm] BILLING CODE 3510-22-P
81 25 Monday, February 8, 2016 Proposed Rules DEPARTMENT OF THE INTERIOR Office of the Secretary 2 CFR Part 1403 [4334-63 167DOI02DM DS62400000 DLSN00000.000000 DX62401] RIN 1090-AB11 Financial Assistance Interior Regulation AGENCY:

Office of the Secretary, Interior.

ACTION:

Proposed rule.

SUMMARY:

This proposed rule establishes the Financial Assistance Interior Regulation (FAIR). The FAIR supplements the OMB Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards (Omni-Circular), which was adopted The Department of the Interior (Department) on December 19, 2014. This proposed rule would consolidate the Department's financial assistance regulations and policies derived from the OMB Omni-Circular.

DATES:

Submit comments on or before April 8, 2016.

ADDRESSES:

You may submit comments on the rulemaking through the Federal eRulemaking Portal at http://www.regulations.gov. Please use Regulation Identifier Number (RIN) 1090-AB08 in your message. Follow the instructions on the Web site for submitting comments.

FOR FURTHER INFORMATION CONTACT:

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 [email protected].

SUPPLEMENTARY INFORMATION: I. Background

On December 26, 2013, the Office of Management and Budget (OMB) published its Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards (referred to as the “Omni-Circular,” 78 FR 78590). The Omni-Circular provided a government-wide framework for Federal awards management; and streamlined administrative requirements, cost principles, and audit requirements for Federal awards including grants and cooperative agreements.

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.

II. Effect on Prior Issuances

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, Applicability.

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.

III. Required Determinations

1. Regulatory Planning and Review (Executive Orders 12866 and 13563). Executive Order (E.O.) 12866 provides that the Office of Information and Regulatory Affairs will review all significant rules. The Office of Information and Regulatory Affairs has determined that this proposed rule is not significant.

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.

2. Regulatory Flexibility Act. This proposed rule will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). The Department of the Interior generally does not award grants to small businesses. The vast majority of Interior grants are awarded to States, local governments, and not-for-profit institutions.

3. Small Business Regulatory Enforcement Fairness Act. This proposed rule is not a major rule under the Small Business Regulatory Enforcement Fairness Act (5 U.S.C. 804(2)). This rule does not have an annual effect on the economy of $100 million or more. The Department generally does not award grants to small businesses. This proposed rule will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions. This proposed rule does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises. This proposed rule establishes regulations for the Department of the Interior financial assistance. The Department's financial assistance is typically offered to States, local governments and not-for-profit institutions. It would not affect business relationships, employment, investment, productivity, innovations, or the ability of U.S.-based enterprises to compete internationally.

4. Unfunded Mandates Reform Act. This proposed rule (1) does not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year; (2) does not have a significant or unique effect on State, local, or tribal governments, or the private sector (3) does not impose requirements on State, local, or tribal governments; and (4) is a reorganization of existing requirements and does not impose any new regulations. A statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531 et seq.) is not required.

5. Takings (E.O. 12630). Under the criteria in section 2 of E.O. 12630, this proposed rule does not have significant takings implications. It does not impose any obligations on the public that would result in a taking. A takings implication assessment is not required.

6. Federalism (E.O. 13132). Under the criteria in section 1 of E.O. 13132, this proposed rule does not have sufficient Federalism implications to warrant the preparation of a Federalism summary impact statement. It would not substantially and directly affect the relationship between the Federal and state governments. A Federalism summary impact statement is not required.

7. Civil Justice Reform (E.O. 12988). This proposed rule complies with the requirements of E.O. 12988. Specifically, this rule (1) meets the criteria of section 3(a) of this E.O. requiring that all regulations be reviewed to eliminate errors and ambiguity and be written to minimize litigation; and (2) meets the criteria of section 3(b)(2) of this E.O. requiring that all regulations be written in clear language and contain clear legal standards.

8. Consultation with Indian tribes (E.O. 13175). The Department strives to strengthen its government-to-government relationship with Indian tribes through a commitment to consultation and recognition of their right to self-governance and tribal sovereignty. We have evaluated this rule under the Department's consultation policy and under the criteria in E.O. 13175 and have determined that it has no substantial direct effect on Federally recognized Indian tribes and that consultation under the Department's tribal consultation policy is not required. This rule does not apply to tribal awards made in accordance with the Indian Self-Determination and Education Assistance Act (Pub. L. 93-638, 88 Stat. 2204), as amended. However, this rule does apply to discretionary grants or cooperative agreements awarded to Tribes pursuant to Sec. 9 of Pub. L. 93-638 when mutually agreed to by the Secretary of the Interior and the tribal organization involved.

9. Paperwork Reduction Act, 44 U.S.C. 3501, et seq. Information collected in the financial assistance application process will be collected and managed in accordance with Omni-Circular section 200.206, Standard application requirements. However this rule does not contain information collection requirements, and a submission to the Office of Management and Budget under the Paperwork Reduction Act (44 U.S.C. 3501 et seq.) is not required. We may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.

10. National Environmental Policy Act. This proposed rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the National Environmental Policy Act of 1969 (NEPA) is not required.

11. Effects on the Energy Supply (E.O. 13211). This proposed rule is not a significant energy action under the definition in E.O. 13211. A Statement of Energy Effects is not required.

12. Plain Language. We are required by section 1(b)(12) of E.O. 12866 and section 3(b)(1)(B) of E.O. 12988 and by the Presidential Memorandum of June 1, 1998, to write all rules in plain language. This means that each rule we publish must (1) be logically organized; (2) use the active voice to address readers directly; (3) use common, everyday words and clear language rather than jargon; (4) be divided into short sections and sentences; and (5) use lists and tables wherever possible. If you feel that we have not met these requirements, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section of this preamble.

List of Subjects in 2 CFR Part 1403

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:

PART 1403—FINANCIAL ASSISTANCE INTERIOR REGULATION Sec. 1403.100 What is the purpose of this part? 1403.101 To whom does the Financial Assistance Interior Regulation (FAIR) apply? 1403.102 Does the FAIR include any exceptions to OMB guidance? 1403.103 Does the Department have any other policies or procedures award recipients must follow? 1403.104-1403.110 [Reserved]. 1403.111 What terms do I need to know? 1403.112 What is conflict of interest? 1403.113 What are mandatory disclosures for financial assistance? 1403.114-1403.203 [Reserved] 1403.204 What is the financial assistance application and merit review process? 1403.205 [Reserved] 1403.206 What are the FAIR requirements for domestic for-profit and foreign entities? 1403.207 What specific conditions apply? 1403.208-1403.400 [Reserved] 1403.401 What are the policies, procedures, and general decision-making criteria for deviations from negotiated indirect cost rates? 1403.402-1403.999 [Reserved] Authority:

5 U.S.C. 301; 2 CFR part 200.

§ 1403.100 What is the purpose of this part?

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.

§ 1403.101 To whom does the Financial Assistance Interior Regulation (FAIR) apply?

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.

§ 1403.102 Does the FAIR include any exceptions to OMB Guidance?

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.

§ 1403.103 Does the Department have any other policies or procedures award recipients must follow?

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.

§ 1403.104-1403.110 [Reserved]
§ 1403.111 What terms do I need to know?

(a) Conflict of interest is any relationship or matter which might place the recipient, its employees, and/or its subrecipients in a position of conflict, real or apparent, between their responsibilities under the agreement and any other interests. Conflicts of interest also include, but are not limited to, direct or indirect financial interests, personal relationships, and business relationships including 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.

(b) Discretionary Federal financial assistance means Federal awards including grants and cooperative agreements that are awarded at the discretion of the agency.

(c) Employment means:

(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.

Non-Federal entity means a State, local government, Indian tribe, institution of higher education, or nonprofit organization that carries out a Federal award as a recipient or subrecipients.

(d) Personal relationship means a Federal award program employee's spouse and/or dependent children, or other members of an employee's household, which may compromise or impair the fairness and impartiality of the Proposal Evaluator and Advisor and Grants Officer in the review, selection, award, and management of a financial assistance award.

(e) Recipient means a non-Federal entity that receives a Federal award directly from a Federal awarding agency to carry out an activity under a Federal program. The term recipient does not include subrecipients.

(f) Subrecipient means a non-Federal entity that receives a subaward from a pass-through entity to carry out part of a Federal program, but does not include an individual that is a beneficiary of such program. A subrecipient may also be a recipient of other Federal awards directly from a Federal awarding agency.

§ 1403.112 What is conflict of interest?

(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, Conflict of interest. Proposal evaluators and advisors, including members of evaluation committees, must render impartial, technically sound, and objective assistance and advice to protect the integrity of the proposal evaluation and award selection process. A Federal employee is prohibited from participating in his or her government capacity in any particular matter when the employee, his or her spouse, minor child, outside business associate, or a person or organization with whom the employee is negotiating or has an arrangement for prospective employment, has a financial interest in the particular matter (see 18 U.S.C. 208).

(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:

Conflict 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).

§ 1403.113 What are mandatory disclosures for financial assistance?

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.

§ 1403.114-1403.203 [Reserved]
§ 1403.204 What is the financial assistance application and merit review process?

(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) Actions required—(1) Competition in grant and cooperative agreement awards. Maximum competition in grant and cooperative agreement awards is expected in awarding discretionary funds, unless otherwise directed by Congress. When grants and cooperative agreements are awarded competitively, the Department requires that the competitive process be fair and impartial, that all applicants be evaluated only on the criteria stated in the announcement, and that no applicant receive an unfair competitive advantage. Synopses of all announcements for open competition, and all modifications/amendments to announcements for open competition, must be posted on Grants.gov (www.grants.gov).

(2) Independent objective evaluation of financial assistance applications and proposals. Announcements and competitions for assistance and agreements must provide for an objective and unbiased process for reviewing applications submitted in response to the announcement and for selecting applicants for award. This requires a comprehensive, impartial, and objective examination of applications based on the criteria contained in the announcement by individuals who have no conflicts of interest with respect to the competing proposal/applications or applicants. Bureaus and offices must exercise due diligence to ensure that applications are reviewed and evaluated by qualified reviewers; applications are scored on the basis of announced criteria; consideration is given to the level of applicant risk and past performance; applications are ranked; and funding determinations are made. Awarding officials must check the System for Award Management (SAM) immediately prior to award to verify that the awardee is not suspended, debarred or otherwise ineligible at the time of award. The SAM review must include a review of the recipient organization's name and principal staff.

(3) Evaluation and Selection Plan for Funding Opportunity Announcements. Bureaus and offices must develop an Evaluation and Selection Plan in concert with the Funding Opportunity Announcement (FOA) to ensure consistency, and to outline and document the selection process. The Evaluation and Selection Plan should be finalized prior to the release of the FOA. An Evaluation and Selection Plan is comprised of five basic elements:

(i) Merit review factors and sub-factors;

(ii) A rating system (e.g., adjectival, color coding, numerical, or ordinal);

(iii) Evaluation standards or descriptions which explain the basis for assignment of the various rating system grades/scores;

(iv) Program policy factors; and

(v) The basis for selection.

(4) Basic review standards. Bureaus and offices must initially screen new applications/proposals to ensure that they meet the following standards before they are subjected to a detailed evaluation utilizing a merit review process. The review system should include three phases: initial screening, threshold review and a merit review. Bureaus and offices may remove an application from funding consideration if it does not pass the Basic Eligibility Screening.

(5) Basic eligibility screening. The initial stage is to consider the timeliness of the application submission, applicant eligibility, and completeness of the documents submitted for review. All applications should be screened to ensure that:

(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, Application for Financial Assistance, SF-424B or SF-424D, Assurances, Detailed Budget Review Sheets; and, if applicable, the SF-LLL, Disclosure of Lobbying.

(6) Completeness. Bureaus and offices may return applications/proposals that are incomplete or otherwise fail to meet the requirements of the Grants.gov FOA to the sender to be corrected or modified/supplemented by the sender. Until the application/proposal meets the above requirements, it shall not be given detailed evaluation. Bureaus and offices may use discretion to determine the length of time for applicants to resolve application deficiencies.

(7) Timeliness. In a competitive review process, bureaus and offices shall consider the timeliness of the application submission. Applications that are submitted beyond the announced deadline date shall be removed from the review process.

(8) Threshold screening. Bureaus and offices are responsible for screening applications and proposals for the adequacy of the budget and compliance with statutory and other requirements. The SF-424 and Detailed Budget Worksheets must be reviewed in accordance with Department of the Interior policy on Financial Assistance Cost Reviews. Bureaus and offices must also consider risk thresholds at this stage of the process. Elements to be considered include organization; single audit submissions, past performance; availability of necessary resources, equipment, or facilities; financial strength and management capabilities; procurement procedures; or procedures for selecting and monitoring subrecipients or sub-vendors, if applicable.

(9) Merit review evaluation screening. This is the final review stage where the technical merit of the application/proposal is reviewed. In the absence of a program rule or statutory requirement, program officials should develop criteria that include all aspects of technical merit. Bureaus and offices should develop criteria that are conceptually independent of each other, but all-encompassing when taken together. While criteria will vary, the basic criteria should focus reviewers' attention on the project's underlying merit (i.e., significance, approach, and feasibility). The criteria should focus not only on the technical details of the proposed project but also on the broader importance or potential impact of the project. The criteria should be easily understood. If the criteria are susceptible to varying interpretations, reviewers will use their own interpretation. Program policy factors may be used during the selection process to provide for consideration of factors that are important to the fulfillment of agency program objectives.

§ 1403.205 [Reserved]
§ 1403.206 What are the FAIR requirements for domestic for-profit and foreign entities?

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) Requirements for domestic for-profit entities. (1) Section 1403.207 contains standard award terms and conditions that bureaus and offices must always apply to for-profit entities; and terms and conditions that bureaus and offices may apply to for-profit entities. Bureaus and offices must always incorporate into awards to domestic for-profit organizations the award terms and conditions that always apply, either directly or by reference.

(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) Requirements for foreign entities. Section 1403.207 of the FAIR contains standard award terms and conditions for foreign entities that include terms and conditions that bureaus and offices must always apply to foreign entities; and terms and conditions that bureaus and offices may apply to foreign entities. Bureaus and offices must always incorporate the terms and conditions that always apply to awards to foreign entities, either directly or by reference. All applicable award terms and conditions apply unless the foreign recipient provides conclusive evidence to the Departmental grant making program, and the program agrees, that 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.

(c) Restrictions on foreign awards. Bureaus and offices must not fund projects in countries determined by the U.S. Department of State to have provided support for acts of international terrorism (see http://www.state.gov/j/ct/list/c14151.htm for more information), and are therefore subject to sanctions that restrict U.S. foreign assistance and other financial transactions, without proper licenses administered by the U.S. Department of the Treasury, Office of Foreign Asset Controls (see http://www.treasury.gov/resourcecenter/sanctions/Pages/default.aspx for more information).

(d) Method of payment for foreign awards. Foreign recipients must not register in or be paid through the Department of the Treasury's Automated Standard Application for Payments (ASAP). Foreign recipients with bank accounts in the United States are paid by Electronic Funds Transfer (EFT) through the Automated Clearing House (ACH). Foreign recipients with bank accounts outside of the United States are paid electronically through the Department of the Treasury's International Treasury Services (ITS) system. The Debt Collection Improvement Act of 1996 requires that all Federal agency payments be made electronically. However, Treasury regulations do allow for some exceptions, including or certain foreign entities. Refer to Department of the Interior guidance on Electronic Funds Transfer Waiver Process at https://www.doi.gov/sites/doi.gov/files/migrated/pam/programs/acquisition/upload/DIAPR-2012-06-Amendment-1-Electronic-Funds-Transfer-Waiver-Process-2.pdf for more information.

(e) Requirements for award terms and conditions. Bureau and office award terms and conditions must be managed in accordance with the requirements in 2 CFR 200.210.

§ 1403.207 What specific conditions apply?

(a) Mandatory award terms and conditions for domestic for-profit entities. The award terms and conditions in:

(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, Federal Leadership on Reducing Text Messaging while Driving, in all awards to domestic for-profit entities.

(e) Whistleblower protection clause. Recipients must insert the following clause in all subawards and contracts related to the prime award that are over the Simplified Acquisition Threshold:

 All awards and related subawards and contracts over the Simplified Acquisition Threshold, and all employees working on applicable awards and related subawards and contracts, are subject to the whistleblower rights and remedies in accordance with the pilot program on award recipient employee whistleblower protections established at 41 U.S.C. 4712 by section 828 of the National Defense Authorization Act for Fiscal Year 2013 (Pub. L. 112-239).

(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) Discretionary award terms and conditions for domestic for-profit entities. The award terms and conditions in 2 CFR part 200, subparts A through E; and 48 CFR part 1, subpart 31.2, Contracts with Commercial Organizations, apply only when the Federal program specifically incorporates them into a for-profit recipient's notice of award.

(f) Indirect cost rates. For information on indirect cost rate negotiations, contact the Interior Business Center (IBC) Indirect Cost Services Division by telephone at (916) 566-7111 or by email at [email protected]. Visit the IBC Indirect Cost Services Division Web site at http://www.doi.gov/ibc/services/Indirect_Cost_Services/index.cfm for more information.

(g) Mandatory award terms and conditions for foreign public entities. (1) The award terms and conditions in 2 CFR part 25, Universal Identifier and System for Award Management; 2 CFR part 170, Reporting Subawards and Executive Compensation; 2 CFR part 175, Award Term for Trafficking in Persons (applicable to private entity subrecipients of foreign public entities); 2 CFR part 1401, Requirements for Drug-Free Workplace (Financial Assistance); and 43 CFR part 18, New Restrictions on Lobbying, always apply to all foreign public entities (see definition in 2 CFR 200.46) and foreign organizations (see definition in 2 CFR 200.47). 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.

(2) Bureaus and offices must also include the terms and conditions of 41 U.S.C. 6306, Prohibition on Members of Congress Making Contracts with Federal Government; and Executive Order 13513, Federal Leadership on Reducing Text Messaging While Driving, in awards to foreign public entities.

(h) Discretionary award terms and conditions for foreign public entities and foreign organizations. (1) The award terms and conditions in 2 CFR part 200 subparts A through E apply to foreign public entities and foreign organizations only when the Federal program specifically incorporates them into a foreign recipient's notice of award. Foreign public entities are also subject to the requirements specific to States, with the following exceptions:

(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, Contracting with Small and Minority Businesses, Women's Business Enterprises, and Labor Surplus Area Firms; and 2 CFR 200.322, Procurement of Recovered Materials, do not apply.

(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) Cost principles. Foreign public entities are subject to the cost principles in 48 CFR part 1, subpart 31.2. Foreign hospitals (i.e., a facility licensed as a hospital under the law of any foreign governmental entity or a facility operated as a hospital by a foreign public entity) are subject to the cost principles in 45 CFR part 74, appendix E.

(j) Indirect costs. (1) The provisions of 2 CFR part 200, appendix IV, Indirect (F&A) Costs Identification and Assignment, and Rate Determination for Nonprofit Organizations, apply to foreign non-profit organizations.

(2) The provisions of 2 CFR part 200 appendix VII, States and Local Government and Indian Tribe Indirect Cost Proposals, apply to foreign public entities. Foreign for-profit entities may contact the Interior Business Center (IBC) Indirect Cost Services by telephone at (916) 566-7111 or by email at [email protected], or visit the IBC Indirect Cost Services Web site athttp://www.doi.govgov/ibc/services/Indirect_Cost_Services/index.cfm for more information.

(3) The provisions of 45 CFR part 74, appendix E, Principles for Determining Costs Applicable to Research and Development under Grants and Contracts with Hospitals, apply to foreign hospitals. The U.S. Department of Health and Human Services (HHS) is the cognizant agency for indirect costs for foreign hospitals. Visit the HHS Cost Allocation Services Web site at https://rates.psc.gov/ for more information.

(4) Indirect costs for institutes of higher education are negotiated with HHS in accordance with 2 CFR part 200 appendix III, Indirect (F&A) Costs Identification and Assignment, and Rate Determination for Institutions of Higher Education (IHEs). Visit the HHS Cost Allocation Services Web site at https://rates.psc.gov/ for more information.

(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).

§ 1403.208-1403.400 [Reserved]
§ 1403.401 What are the policies, procedures, and general decision-making criteria for deviations from negotiated indirect cost rates?

(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) Distribution basis. For all deviations to the Federal negotiated indirect cost rate, including statutory, regulatory, programmatic, and voluntary, the basis of direct costs against which the indirect cost rate is applied must be:

(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) Indirect cost rate deviation required by statute or regulation. In accordance with 2 CFR 200.414(c)(1), a Federal agency must use a rate other than the Federal negotiated rate where required by Federal statute or regulation. For such instances within the Department, the official award file must document the specific statute or regulation that required the deviation.

(3) Indirect cost rate reductions used as cost-share. Instances where the recipient elects to use a rate lower than the federally negotiated indirect cost rate, and uses the balance of the unrecovered indirect costs to meet a cost-share or matching requirement required by the program and/or statute, are not considered a deviation from 2 CFR 200.414(c), as the federally negotiated indirect cost rate is being applied under the agreement in order to meet the terms and conditions of the award.

(4) Programmatic indirect cost rate deviation approval process. The following requirements apply for review, approval, and posting of programmatic indirect cost rate waivers:

(5) Program qualifications. Programs that have instituted a program-wide requirement and governance process for deviations from federally negotiated indirect cost rates may qualify for a programmatic deviation approval.

(6) Deviation requests. Deviation requests must be submitted by the responsible senior program manager to the Department Office of Acquisition and Property Management. The request for deviation approval must include a description of the program, and the governance process for negotiating and/or communicating to recipients the indirect cost rate requirements under the program. The program must make its governance documentation, rate deviations, and other program information publicly available.

(7) Approvals. Programmatic deviations must be approved, in writing, by the Director, Office of Acquisition and Property Management. Approved deviations will be made publicly available along with the governance documentation for the program.

(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) Voluntary indirect cost rate reduction. On an award-specific basis, an applicant and/or proposed recipient may elect to reduce or eliminate the indirect cost rate applied to costs under that award. The election must be voluntary and cannot be required by the awarding official, funding opportunity announcement, program, or other non-statutory or non-regulatory requirements. For these award-specific and voluntary reductions, the Department can accept the lower rate provided the official file clearly documents the recipient's voluntary election.

(10) Unrecovered indirect costs. In accordance with 2 CFR 200.405, indirect costs not recovered due to deviations to the federally negotiated rate are not allowable for recovery via any other means.

(b) [Reserved]

§ 1403.402-1403.999 [Reserved]
Dated: January 20, 2016. Kristen J. Sarri, Principal Deputy Assistant Secretary—Policy, Management and Budget.
[FR Doc. 2016-02039 Filed 2-5-16; 8:45 am] BILLING CODE 4334-63-P
OFFICE OF PERSONNEL MANAGEMENT 5 CFR PART 250 RIN 3206-AL98 Personnel Management in Agencies AGENCY:

Office of Personnel Management.

ACTION:

Proposed rule.

SUMMARY:

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).

DATES:

Comments must be received on or before April 8, 2016.

ADDRESSES:

You may submit comments, identified by RIN number 3206-AL98, using any of the following methods:

Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.

Mail: Veronica Villalobos, Principal Deputy Associate Director, Employee Services, Office of Personnel Management, Room 7460, 1900 E Street NW., Washington, DC 20415.

FOR FURTHER INFORMATION CONTACT:

For information contact Jan Chisolm-King by email at [email protected] or by telephone at (202) 606-1958.

SUPPLEMENTARY INFORMATION:

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.

Proposed August 2011 Regulations

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.

Recent Developments

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).

The Government Performance and Results Act (GPRA) Modernization Act (GPRAMA)

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 goals are to be achieved with respect to training, skills, and other HC resources required to meet those performance goals” (Pub. L. 111-352).

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—

review applicable directives to agencies related to the development or submission of agency human capital and other workforce plans and reports in connection with recruitment, hiring, promotion, retention, professional development, and training policies and practices, and develop a strategy for consolidating such agency plans and reports where appropriate and permitted by law (E.O. 13583, Sec. 2(b)(ii)) HCAAF Revitalization

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.

New Human Capital Framework

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.

Proposed Regulation

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.

Employee Survey Enhancements

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.

Survey Background

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 (e.g., ODNI, DOD, OMB, DOI, VA) reviewed the FEVS through a stepwise process of data analysis, stakeholder engagement, solicitation of expert opinion and input from OMB and recommended a concise subset of questions critical to the intent of the original statute.

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).

Executive Order 13563 and Executive Order 12866, Regulatory Review

The Office of Management and Budget has reviewed this proposed rule in accordance with E.O. 13563 and 12866.

Paperwork Reduction Act

This document does not contain proposed information collection requirements subject to the Paperwork Reduction Act of 1995 (Pub. L. 104-13).

Regulatory Flexibility Act

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.

List of Subjects in 5 CFR Part 250

Authority for personnel actions in agencies, Employee surveys, Strategic human capital management.

Office of Personnel Management. Beth F. Cobert, Acting Director.

Accordingly, OPM is proposing to amend title 5, Code of Federal Regulations, as follows:

PART 250—PERSONNEL MANAGEMENT IN AGENCIES Subpart B—Strategic Human Capital Management 1. Subpart B is revised to read as follows: Subpart B—Strategic Human Capital Management Sec. 250.201 Coverage and purpose. 250.202 Definitions. 250.203 Strategic human capital management. 250.204 Agency roles and responsibilities. 250.205 Metrics. 250.206 Consequences of improper agency actions. Subpart B—Strategic Human Capital Management Authority:

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)

§ 250.201 Coverage and purpose.

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.

§ 250.202 Definitions.

Chief Human Capital Officer (CHCO) is the agency's senior leader whose primary duty is to:

(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.

CHCO agency is an Executive agency, as defined by 5 U.S.C. 105, which is required by 5 U.S.C. 1401 to appoint a CHCO.

Director of OPM is, among other things, the President's advisor on actions that may be taken to promote an efficient civil service and a systematic application of the merit system principles, including recommending policies relating to the selection, promotion, transfer, performance, pay, conditions of service, tenure, and separation of employees. The Director of OPM provides governmentwide leadership and direction in the strategic management of the Federal workforce.

Evaluation system is an agency's overarching system for evaluating the results of all human capital planning to inform the agency's continuous process improvement efforts. This system also is used for ensuring compliance with all applicable statutes, rules, regulations, and agency policies.

Federal Workforce Strategic Priorities Report is a strategic human capital report, published by OPM by the first Monday in February of any year in which the term of the President commences. The report communicates key governmentwide human capital priorities and suggested strategies. The report informs agency strategic and human capital planning.

Focus areas are areas that agencies and human capital practitioners must focus on to achieve a system's standard.

HRStat is a strategic human capital performance evaluation process that identifies, measures, and analyzes human capital data to inform the impact of agency human capital on organizational results and to improve human capital outcomes. HRStat is a component of an agency's strategic planning and alignment, and evaluation systems that are part of the Human Capital Framework..

Human Capital Evaluation Framework underlies the three human capital evaluation mechanisms (e.g., HRStat, Audits, and Human Capital Strategic Reviews) to create a central evaluation framework that integrates the outcomes from each to provide OPM and agencies with an understanding of how human capital policies and programs are supporting missions.

Human Capital Framework (HCF) provides comprehensive guidance on the principles of strategic human capital management in the Federal Government. The framework provides direction on human capital planning, implementation, and evaluation in the Federal environment.

Human Capital Operation Plan (HCOP) is an agency's annual human capital implementation document, which describes how an agency will support the human capital elements stated within its Annual Performance Plan (APP). Program specific workforce investments and strategies (e.g., hiring, closing skills gaps, etc.) should be incorporated into the APPs as appropriate. The HCOP should clearly execute each of the four systems of the HCF. The HC Strategy, HCOP, and HCSR should align with GPRAMA annual performance plans and timelines.

Human Capital Strategic Review (HCSR) is OPM's annual review of an agency's design and implementation of its HCOP, independent audit, and HRStat programs to support mission accomplishment and human capital outcomes.

Independent audit program is a component of an agency's evaluation system designed to review all human capital management systems and select human resources transactions to ensure efficiency, effectiveness, and legal and regulatory compliance.

Skills gap is a variance between the current and projected workforce size and skills needed to ensure an agency has a cadre of talent available to meet its mission, and make progress towards its goals and objectives.

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, 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.

§ 250.203 Strategic human capital management systems and standards.

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) Strategic planning and alignment. A system that ensures agency human capital programs are aligned with agency mission, goals, and objectives through analysis, planning, investment, and measurement. The standards for the strategic planning and alignment system require an agency to ensure an agency's human capital management strategies, plans, and practices—

(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) Talent management. A system that promotes a high-performing workforce, identifies and closes skills gaps, and implements and maintains programs to attract, acquire, develop, promote, and retain quality and diverse talent. The standards for the Talent Management system require an agency to—

(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) Performance culture. A system that engages, develops, and inspires a diverse, high-performing workforce by creating, implementing, and maintaining effective performance management strategies, practices, and activities that support mission objectives. The standards for the performance culture system require an agency to have—

(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) Evaluation. A system that contributes to agency performance by monitoring and evaluating outcomes of its human capital management strategies, policies, programs, and activities by meeting the following standards—

(1) Ensuring compliance with merit system principles; and

(2) Identifying, implementing, and monitoring process improvements.

§ 250.204 Agency roles and responsibilities.

(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 (e.g., human capital policies, goals, objectives, and day-to-day operational needs). The HCOP will be made available to OPM upon request. Guidance on preparing the human capital portions of an agency's APP can be found in OMB Circular A-11, part 6, section 200. The HCOP must—

(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 (e.g., staff full-time equivalents, training, analytical software, etc.) into the agency's annual budget process.

§ 250.205 System metrics.

OPM reserves the right to provide additional guidance regarding metrics as the need arises.

§ 250.206 Consequences of improper agency actions.

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.

Subpart C—Employee Surveys 2. Subpart C is revised to read as follows: Subpart C—Employee Surveys Sec. 250.301 Definitions. 250.302 Survey requirements. 250.303 Availability of results. Subpart C—Employee Surveys Authority:

5 U.S.C. 105; 5 U.S.C. 7101 note; Public Law 108-136

§ 250.301 Definitions.

Agency means an Executive agency, as defined in 5 U.S.C. 105.

Senior leaders are the heads of departments/agencies and their immediate leadership team responsible for directing the policies and priorities of the department/agency. May hold either a political or career appointment and is typically a member of the senior executive service.

Managers are those in management positions who typically supervise one or more supervisors.

Supervisors are first-line supervisors typically responsible for employees' performance appraisals and leave approval. Does not supervise other supervisors.

§ 250.302 Survey requirements.

(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:

(1) Leadership and Management practices that contribute to agency performance My work unit has the job-relevant skills necessary to accomplish organizational goals. Managers communicate the goals of the organization. (2) Employee Satisfaction with— (i) Leadership Policies and Practices How satisfied are you with your involvement in decisions that affect your work? How satisfied are you with the information you receive from management on what's going on in your organization? (ii) Work Environment The people I work with cooperate to get the job done. My workload is reasonable. (iii) Rewards and Recognition In my work unit, differences in performance are recognized in a meaningful way. How satisfied are you with the recognition you receive for doing a good job? (iv) Opportunities for professional development and growth I am given a real opportunity to improve my skills in my organization. My talents are used well in the workplace. (v) Opportunity to contribute to achieving organizational mission I know how my work relates to the agency's goals.
§ 250.303 Availability of results.

(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.

[FR Doc. 2016-02112 Filed 2-5-16; 8:45 am] BILLING CODE 6325-39-P
DEPARTMENT OF TRANSPORTATION Federal Aviation Administration 14 CFR Part 39 [Docket No. FAA-2016-0462; Directorate Identifier 2015-NM-144-AD] RIN 2120-AA64 Airworthiness Directives; The Boeing Company Airplanes AGENCY:

Federal Aviation Administration (FAA), DOT.

ACTION:

Notice of proposed rulemaking (NPRM).

SUMMARY:

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.

DATES:

We must receive comments on this proposed AD by March 24, 2016.

ADDRESSES:

You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:

Federal eRulemaking Portal: Go to http://www.regulations.gov. Follow the instructions for submitting comments.

Fax: 202-493-2251.

Mail: U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 20590.

Hand Delivery: Deliver to Mail address above between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.

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 https://www.myboeingfleet. You may view this referenced service information at the FAA, Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, WA. For information on the availability of this material at the FAA, call 425-227-1221. It is also available on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-0462.

Examining the AD Docket

You may examine the AD docket on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-0462; or in person at the Docket Management Facility between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains this proposed AD, the regulatory evaluation, any comments received, and other information. The street address for the Docket Office (phone: 800-647-5527) is in the ADDRESSES section. Comments will be available in the AD docket shortly after receipt.

FOR FURTHER INFORMATION 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: [email protected].

SUPPLEMENTARY INFORMATION: Comments Invited

We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2016-0462; Directorate Identifier 2015-NM-144-AD” at the beginning of your comments. We specifically invite comments on the overall regulatory, economic, environmental, and energy aspects of this proposed AD. We will consider all comments received by the closing date and may amend this proposed AD because of those comments.

We will post all comments we receive, without change, to http://www.regulations.gov, including any personal information you provide. We will also post a report summarizing each substantive verbal contact we receive about this proposed AD.

Discussion

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 a hole in the hydraulic tube and consequent loss of hydraulic fluid, possibly resulting in a fire in the MLG wheel well.

Related Service Information Under 1 CFR Part 51

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 ADDRESSES section.

FAA's Determination

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.

Proposed AD Requirements

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 http://www.regulations.gov by searching for and locating Docket No. FAA-2016-0462.

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.

Costs of Compliance

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:

Estimated Costs Action Labor cost Parts cost Cost per
  • product
  • Cost on U.S. operators
    Inspection and Installation 2 work-hours × $85 per hour = $170 $9 $179 $227,330

    We have received no definitive data that would enable us to provide cost estimates for the on-condition actions specified in this proposed AD.

    Authority for This Rulemaking

    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.

    Regulatory Findings

    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.

    List of Subjects in 14 CFR Part 39

    Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.

    The Proposed Amendment

    Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

    PART 39—AIRWORTHINESS DIRECTIVES 1. The authority citation for part 39 continues to read as follows: Authority:

    49 U.S.C. 106(g), 40113, 44701.

    § 39.13 [Amended]
    2. The FAA amends § 39.13 by adding the following new airworthiness directive (AD): The Boeing Company: Docket No. FAA-2016-0462; Directorate Identifier 2015-NM-144-AD. (a) Comments Due Date

    We must receive comments by March 24, 2016.

    (b) Affected ADs

    None.

    (c) Applicability

    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.

    (d) Subject

    Air Transport Association (ATA) of America Code 29, Hydraulic power.

    (e) Unsafe Condition

    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.

    (f) Compliance

    Comply with this AD within the compliance times specified, unless already done.

    (g) Inspection and Corrective Action and Clamp Installation

    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 accordance with the Accomplishment Instructions of Boeing Alert Service Bulletin 737-29A1119, dated August 4, 2015. Do all applicable corrective actions before further flight.

    (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.

    (h) Alternative Methods of Compliance (AMOCs)

    (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: [email protected].

    (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.

    (i) Related Information

    (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: [email protected].

    (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 https://www.myboeingfleet. You may view this referenced service information at the FAA, Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, WA. For information on the availability of this material at the FAA, call 425-227-1221.

    Issued in Renton, Washington, on January 27, 2016. Michael Kaszycki, Acting Manager, Transport Airplane Directorate, Aircraft Certification Service.
    [FR Doc. 2016-02193 Filed 2-5-16; 8:45 am] BILLING CODE 4910-13-P
    DEPARTMENT OF THE INTERIOR Office of Surface Mining Reclamation and Enforcement 30 CFR Part 936 [SATS No. OK-037-FOR; Docket ID: OSM-2015-0006; S1D1S SS08011000 SX064A000 167S180110; S2D2S SS08011000 SX064A000 16XS501520] Oklahoma Regulatory Program AGENCY:

    Office of Surface Mining Reclamation and Enforcement, Interior.

    ACTION:

    Proposed rule; public comment period and opportunity for public hearing on proposed amendment.

    SUMMARY:

    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.

    DATES:

    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.

    ADDRESSES:

    You may submit comments, identified by SATS No. OK-037-FOR, by any of the following methods:

    Mail/Hand Delivery: Director, Tulsa Field Office, Office of Surface Mining Reclamation and Enforcement, 1645 South 101st East Avenue, Suite 145, Tulsa, Oklahoma 74128-4629.

    Fax: (918) 581-6419.

    Federal eRulemaking Portal: The amendment has been assigned Docket ID OSM-2015-0006. If you would like to submit comments go to http://www.regulations.gov. Follow the instructions for submitting comments.

    Instructions: All submissions received must include the agency name and docket number for this rulemaking. For detailed instructions on submitting comments and additional information on the rulemaking process, see the “Public Comment Procedures” heading of the SUPPLEMENTARY INFORMATION section of this document.

    Docket: For access to the docket to review copies of the Oklahoma program, this amendment, a listing of any scheduled public hearings, and all written comments received in response to this document, you must go to the address listed below during normal business hours, Monday through Friday, excluding holidays. You may receive one free copy of the amendment by contacting OSMRE's Tulsa Field Office or the full text of the program amendment is available for you to read at www.regulations.gov.

    Elaine Ramsey, Director, Tulsa Field Office, Office of Surface Mining Reclamation and Enforcement, 1645 South 101st East Avenue, Suite 145, Tulsa, Oklahoma 74128-4629.

    Telephone: (918) 581-6430.

    Email: [email protected].

    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.

    FOR FURTHER INFORMATION CONTACT:

    Elaine Ramsey, Director, Tulsa Field Office. Telephone: (918) 581-6430.

    SUPPLEMENTARY INFORMATION: I. Background on the Oklahoma Program II. Description of the Proposed Amendment III. Public Comment Procedures IV. Procedural Determinations I. Background on the Oklahoma Program

    Section 503(a) of the Act permits a State to assume primacy for the regulation of surface coal mining and reclamation operations on non-Federal and non-Indian lands within its borders by demonstrating that its program includes, among other things, “. . . State law which provides for the regulation of surface coal mining and reclamation operations in accordance with the requirements of this Act . . .; and rules and regulations consistent with regulations issued by the Secretary pursuant to this Act.” See 30 U.S.C. 1253(a)(1) and (7). On the basis of these criteria, the Secretary of the Interior conditionally approved the Oklahoma program on January 19, 1981. You can find background information on the Oklahoma program, including the Secretary's findings, the disposition of comments, and the conditions of approval of the Oklahoma program in the January 19, 1981, Federal Register (46 FR 4902). You can also find later actions concerning the Oklahoma program and program amendments at 30 CFR 936.10, 936.15, and 936.16.

    II. Description of the Proposed Amendment

    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 et seq.). Oklahoma submitted the proposed amendment on its own initiative. Below is a summary of Oklahoma's proposed changes. The full text of the program amendment is available for you to read at the locations listed above under ADDRESSES or at www.regulations.gov.

    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.

    1. Subchapter 15. Requirements for Permits and Permit Processing

    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).

    2. Subchapter 29. Underground Mining Permit Applications: Minimum Requirements for Information on Environmental Resources

    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).

    3. Subchapter 43. Permanent Program Performance Standards: Surface Mining Standards

    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).

    4. Subchapter 45. Permanent Program Performance Standards: Underground Mining Activities

    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).

    5. Subchapter 47. Special Permanent Program Performance Standards: Auger Mining

    Oklahoma proposes to add new language regarding surface drainage during auger mining operations in section 460:20-47-4(d).

    III. Public Comment Procedures

    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.

    Electronic or Written Comments

    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 DATES) or sent to an address other than those listed (see ADDRESSES) will be included in the docket for this rulemaking and considered.

    Public Availability of Comments

    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.

    Public Hearing

    If you wish to speak at the public hearing, contact the person listed under FOR FURTHER INFORMATION CONTACT by 4:00 p.m., central time on February 23, 2016. If you are disabled and need reasonable accommodations to attend a public hearing, contact the person listed under FOR FURTHER INFORMATION CONTACT. We will arrange the location and time of the hearing with those persons requesting the hearing. If no one requests an opportunity to speak, we will not hold a hearing.

    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.

    Public Meeting

    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 FOR FURTHER INFORMATION CONTACT. All such meetings are open to the public and, if possible, we will post notices of meetings at the locations listed under ADDRESSES. We will make a written summary of each meeting a part of the administrative record.

    IV. Procedural Determinations Executive Order 12866—Regulatory Planning and Review

    This rule is exempted from review by the Office of Management and Budget (OMB) under Executive Order 12866.

    Other Laws and Executive Orders Affecting Rulemaking

    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 Federal Register indicating receipt of the proposed amendment, its text or a summary of its terms, and an opportunity for public comment. We conclude our review of the proposed amendment after the close of the public comment period and determine whether the amendment should be approved, approved in part, or not approved. At that time, we will also make the determinations and certifications required by the various laws and executive orders governing the rulemaking process and include them in the final rule.

    List of Subjects in 30 CFR Part 936

    Intergovernmental relations, Surface mining, Underground mining.

    Dated: October 15, 2015. Ervin J. Barchenger, Regional Director, Mid-Continent Region. Note:

    This document was received by the Office the Federal Register on February 3, 2016.

    [FR Doc. 2016-02463 Filed 2-5-16; 8:45 am] BILLING CODE 4310-05-P
    DEPARTMENT OF THE INTERIOR Office of Surface Mining Reclamation and Enforcement 30 CFR Part 946 [SATS No. VA-127-FOR; Docket ID: OSM-2015-0003; S1D1S SS08011000 SX064A000 67F 167S180110; S2D2S SS08011000 SX064A000 33F 16XS501520] Virginia Regulatory Program AGENCY:

    Office of Surface Mining Reclamation and Enforcement, Interior.

    ACTION:

    Proposed rule; reopening of the public comment period.

    SUMMARY:

    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.

    DATES:

    We will accept written comments on this amendment until 4:00 p.m., Eastern Standard Time (E.S.T.), March 9, 2016.

    ADDRESSES:

    You may submit comments, identified by SATS No. VA-127-FOR, Docket ID: OSM-2015-003 by any of the following methods:

    Mail/Hand Delivery: Mr. Earl Bandy, Field Office Director, Knoxville Field Office, Office of Surface Mining Reclamation and Enforcement, 710 Locust Street, 2nd Floor, Knoxville, Tennessee 37902.

    Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.

    Instructions: All submissions received must include the agency name and docket number for this rulemaking. For detailed instructions on submitting comments and additional information on the rulemaking process, see the “Public Comment Procedures” heading of the SUPPLEMENTARY INFORMATION section of the proposed rule published in the Federal Register on October 22, 2015, (80 FR 63933).

    Docket: For access to the docket to review copies of the Virginia program, this amendment, a listing of any scheduled public hearings, and all written comments received in response to this document, you must go to the address listed below during normal business hours, Monday through Friday, excluding holidays. You may receive one free copy of the amendment by contacting OSMRE's Knoxville Field Office or the full text of the program amendment is available for you to read at www.regulations.gov.

    Mr. Earl Bandy, Field Office Director, Knoxville Field Office, Office of Surface Mining Reclamation and Enforcement, 710 Locust Street, 2nd Floor, Knoxville, Tennessee 37902. Telephone: (865) 545-4103 ext 186. Email: [email protected].

    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. Telephone: (276) 523-8271. Email: [email protected].

    FOR FURTHER INFORMATION CONTACT:

    Mr. Earl Bandy, Field Office Director, Knoxville Field Office. Telephone: (865) 545-4103 ext 186. Email: [email protected].

    SUPPLEMENTARY INFORMATION:

    On October 22, 2015, we published a proposed rule in the Federal Register that would revise the Virginia program (80 FR 63933) (Administrative Record No. VA 2026). The amendment involves statutory provisions of the Virginia Coal Surface Mining Control and Reclamation Act of 1979 (VASMCRA) and regulation changes that 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.

    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 ADDRESSES or at www.regulations.gov.

    Dated: December 9, 2015. Thomas D. Shope, Regional Director, Appalachian Region.
    [FR Doc. 2016-02460 Filed 2-5-16; 8:45 am] BILLING CODE 4310-05-P
    DEPARTMENT OF VETERANS AFFAIRS 38 CFR Part 17 RIN 2900-AP42 Prescriptions in Alaska and U.S. Territories and Possessions AGENCY:

    Department of Veterans Affairs.

    ACTION:

    Proposed rule.

    SUMMARY:

    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.

    DATES:

    Comments must be received by VA on or before April 8, 2016.

    ADDRESSES:

    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 http://www.Regulations.gov. Comments should indicate that they are submitted in response to “RIN 2900—[WP2013-04]—Prescriptions in Alaska and U.S. Territories and Possessions.” All comments received will be available for public inspection in the Office of Regulation Policy and Management, Room 1063B, between the hours of 8 a.m. and 4:30 p.m., Monday through Friday (except holidays). Call (202) 461-4902 for an appointment. (This is not a toll-free number.) In addition during the comment period, comments may be viewed online through the Federal Docket Management System at http://www.Regulations.gov.

    FOR FURTHER INFORMATION CONTACT:

    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.)

    SUPPLEMENTARY INFORMATION:

    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.

    Effect of Rulemaking

    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.

    Paperwork Reduction Act

    This proposed rule contains no provisions constituting a collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3521).

    Regulatory Flexibility Act

    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 Order 12866 and 13563

    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 regulatory action under Executive Order 12866. VA's impact analysis can be found as a supporting document at http://www.regulations.gov, usually within 48 hours after the rulemaking document is published. Additionally, a copy of the rulemaking and its impact analysis are available on VA's Web site at http://www.va.gov/orpm/, by following the link for “VA Regulations Published From FY 2004 Through Fiscal Year to Date.

    Unfunded Mandates

    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.

    Catalog of Federal Domestic Assistance

    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.

    Signing Authority

    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.

    List of Subjects in 38 CFR Part 17

    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.

    Dated: February 2, 2016. William F. Russo, Director, Office of Regulation Policy & Management, Office of the General Counsel, Department of Veterans Affairs.

    For the reasons set forth in the preamble, we propose to amend 38 CFR part 17 as follows:

    PART 17—MEDICAL 1. The authority citation for part 17 continues to read as follows: Authority:

    38 U.S.C. 501, and as noted in specific sections.

    2. Amend § 17.96 by revising the introductory paragraph to read as follows:
    § 17.96 Medication prescribed by non-VA physicians.

    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:

    [§ 17.97 Removed and Reserved]
    3. Remove § 17.97 and mark as reserved for future use.
    [FR Doc. 2016-02350 Filed 2-5-16; 8:45 am] BILLING CODE 8320-01-P
    ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 52 [EPA-R09-OAR-2015-0807; FRL-9941-94-Region 9] Approval of California Air Plan Revisions, Department of Pesticide Regulations AGENCY:

    Environmental Protection Agency (EPA).

    ACTION:

    Proposed rule.

    SUMMARY:

    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.

    DATES:

    Any comments must arrive by March 9, 2016.

    ADDRESSES:

    Submit your comments, identified by Docket ID No. EPA-R09-OAR-2015-0807 at http://www.regulations.gov, or via email to [email protected]. For comments submitted at Regulations.gov, follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from Regulations.gov. For either manner of submission, the EPA may publish any comment received to its public docket. Do not submit electronically any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (i.e. on the web, cloud, or other file sharing system). For additional submission methods, please contact the person identified in the FOR FURTHER INFORMATION CONTACT section. For the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit http://www2.epa.gov/dockets/commenting-epa-dockets.

    FOR FURTHER INFORMATION CONTACT:

    Nancy Levin, EPA Region IX, (415) 972-3848, [email protected].

    SUPPLEMENTARY INFORMATION:

    Throughout this document, “we,” “us” and “our” refer to the EPA.

    Table of Contents I. The State's Submittal A. What rules did the State submit? B. Are there other versions of these rules? C. What is the purpose of the submitted rules and rule revisions? II. The EPA's Evaluation and Action A. How is the EPA evaluating the rules? B. Do the rules meet the evaluation criteria? C. EPA Recommendations To Further Improve the Rules D. Public Comment and Proposed Action III. Incorporation by reference IV. Statutory and Executive Order Reviews I. The State's Submittal A. What rules did the State submit?

    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).

    Table 1—Submitted Rules Local agency Rule No. Rule title Adopted/amended Submitted CDPR 3 CCR 6452 Reduced VOC Emissions Field Fumigation Methods 05/23/13 02/04/15 CDPR 3 CCR 6452.2 VOC Emission Limits 05/23/13 02/04/15 CDPR 3 CCR 6558 Recommendations for Use of Nonfumigants in the San Joaquin Valley (SJV) Ozone Nonattainment Area (NAA) 05/23/13 02/04/15 CDPR 3 CCR 6577 Sales of Nonfumigants for Use in the SJV Ozone NAA 05/23/13 02/04/15 CDPR 3 CCR 6864 Criteria for Identifying Pesticides as Toxic Air Contaminants 05/23/13 02/04/15 CDPR 3 CCR 6880 Criteria to Designate Low-VOC or High-VOC Nonfumigant Pesticide Products 05/23/13 02/04/15 CDPR 3 CCR 6881 Annual VOC Emissions Inventory Report 05/23/13 02/04/15 CDPR 3 CCR 6883 Recommendation Requirements in the SJV Ozone NAA 05/23/13 02/04/15 CDPR 3 CCR 6884 SJV Ozone NAA Use Prohibitions 05/23/13 02/04/15 CDPR 3 CCR 6886 Dealer Responsibilities for the SJV Ozone NAA 05/23/13 02/04/15

    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.

    B. Are there other versions of these rules?

    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).

    C. What is the purpose of the submitted rules and rule revisions?

    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” (i.e., the estimated VOC emissions if the prohibitions were not in effect) for pesticides in the SJV ozone NAA comply with the 17.2 tons per day limit for at least two consecutive years. The rules include a calculation to determine the “hypothetical emissions.” The rules also require pest control dealers to provide customers written information about these restrictions and to indicate on the invoice that the written information was provided. Pest control advisors are prohibited from recommending a restricted nonfumigant product, unless it qualifies under an exception.

    The EPA's technical support document (TSD) has more information about these rules.

    II. The EPA's Evaluation and Action A. How is the EPA evaluating the 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:

    1. “Issues Relating to VOC Regulation Cutpoints, Deficiencies, and Deviations,” EPA, May 25, 1988 (the Bluebook, revised January 11, 1990). 2. “Guidance Document for Correcting Common VOC & Other Rule Deficiencies,” EPA Region 9, August 21, 2001 (the Little Bluebook). B. Do the rules meet the evaluation criteria?

    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.

    C. EPA Recommendations To Further Improve the Rules

    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.

    E. Public Comment and Proposed Action

    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 from the public on this proposal until March 9, 2016. Unless we receive convincing new information during the comment period, we intend to publish a final approval action that will incorporate these rules into the federally enforceable SIP.

    III. Incorporation by Reference

    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 www.regulations.gov and in hard copy at the appropriate EPA office (see the ADDRESSES section of this preamble for more information).

    IV. Statutory and Executive Order Reviews

    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 et seq.);

    • 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 et seq.);

    • 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).

    List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.

    Authority:

    42 U.S.C. 7401 et seq.

    Dated: January 14, 2016. Jared Blumenfeld, Regional Administrator, Region IX.
    [FR Doc. 2016-02314 Filed 2-5-16; 8:45 am] BILLING CODE 6560-50-P
    ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 52 [EPA-R06-OAR-2012-0953; FRL-9941-96-Region 6] 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 AGENCY:

    Environmental Protection Agency (EPA).

    ACTION:

    Proposed rule.

    SUMMARY:

    The Environmental Protection Agency (EPA) is proposing to approve elements of State Implementation Plan (SIP) submissions from the State of Texas for Ozone (O3) and Nitrogen Dioxide (NO2) National Ambient Air Quality Standards (NAAQS). These submittals address how the existing SIP provides for implementation, maintenance, and enforcement of the 2008 O3 and 2010 NO2 NAAQS (infrastructure SIPs or i-SIPs). These i-SIPs ensure that the State's SIP is adequate to meet the state's responsibilities under the Federal Clean Air Act (CAA).

    DATES:

    Written comments must be received on or before March 9, 2016.

    ADDRESSES:

    Submit your comments, identified by Docket No. EPA-R06-OAR-2012-0953 at http://www.regulations.gov or via email to [email protected]. Follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from Regulations.gov. The EPA may publish any comment received to its public docket. Do not submit electronically any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (i.e. on the web, cloud, or other file sharing system). For additional submission methods, please contact Sherry Fuerst, (214) 665-6454, [email protected]. For the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit http://www2.epa.gov/dockets/commenting-epa-dockets.

    Docket: The index to the docket for this action is available electronically at www.regulations.gov and in hard copy at EPA Region 6, 1445 Ross Avenue, Suite 700, Dallas, Texas. While all documents in the docket are listed in the index, some information may be publicly available only at the hard copy location (e.g., copyrighted material), and some may not be publicly available at either location (e.g., CBI).

    FOR FURTHER INFORMATION CONTACT:

    Sherry Fuerst, telephone (214) 665-6454, [email protected]. To inspect the hard copy materials, please schedule an appointment with her or Bill Deese at (214) 665-7253.

    SUPPLEMENTARY INFORMATION:

    Throughout this document, “we,” “us,” or “our” means the EPA.

    I. Background

    On March 12, 2008, we revised the primary and secondary O3 NAAQS (hereafter the 2008 O3 NAAQS) 1 to 0.075 parts per million (ppm), expressed to three decimal places, based on a 3-year average of the fourth-highest maximum 8-hour average concentration. (73 FR 16436, March 27, 2008).2 Primary NAAQS protect public health and secondary NAAQS protect the public welfare (CAA section 109).

    1 The previous O3 NAAQS were issued in 1997. The 1997 primary and secondary NAAQS were established as 0.08 ppm not to be exceeded as determined by the 3-year average of the annual fourth-highest daily maximum 8-hour concentrations (62 FR 38856, July 18, 1997).

    2 Although the effective date of the Federal Register notice for the final rule was May 27, 2008, the rule was signed by the Administrator and publicly disseminated on March 12, 2008. Therefore, the deadline for submittal of infrastructure SIPs for the 2008 O3 NAAQS was March 12, 2011.

    Likewise, on January 22, 2010, we revised the primary national ambient air quality standard (hereafter the 2010 NO2 NAAQS) 3 for oxides of nitrogen as measured by nitrogen dioxide (NO2), for 1-hour standard at a level of 100 ppb, based on the 3-year average of the 98th percentile of the yearly distribution of 1-hour daily maximum concentrations, to supplement the existing annual standard. We also established requirements for a NO2 monitoring network that includes monitors at locations where maximum NO2 concentrations are expected to occur, including within 50 meters of major roadways, as well as monitors sited to measure the area-wide NO2 concentrations that occur more broadly across communities. (75 FR 6474, February 9. 2010).4

    3 The previous NO2 NAAQS was issued in 1996. It established a primary and secondary standards of for nitrogen dioxide (NO2) as 0.053 parts per million (ppm) (100 micrograms per meter cubed (g/m3)) annual arithmetic average. (61 FR 52852, October 8, 1996).

    4 Although the effective date of the Federal Register notice for the final rule was April 12, 2010, the rule was signed by the Administrator and publicly disseminated on January 22, 2010. Therefore, the deadline for submittal of infrastructure SIPs for the 2008 NO2 NAAQS was January 22, 2013.

    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.5 The Chairman of the Texas Commission on Environmental Quality (TCEQ) submitted i-SIP revisions to address these revised NAAQS.

    5 “Guidance on Infrastructure State Implementation Plan (SIP) Elements under Clean Air Act Sections 110(a)(1) and 110(a)(2),” Memorandum from Stephen D. Page, September 13, 2013.

    We are proposing to approve the Texas i-SIP submittals for the 2008 Ozone and 2010 NO2 NAAQS.6 Copies of these SIP submissions are included in the docket for this proposed rulemaking.

    6 Additional information on: The history of the O3 and NO2 NAAQS, its levels, forms and, determination of compliance; EPA's approach for reviewing i-SIPs; the details of the SIP submittal and EPA's evaluation; the effect of recent court decisions on i-SIPs; the statute and regulatory citations in the Texas SIP specific to this review; the specific i-SIP applicable CAA and our regulatory citations; Federal Register Notice citations for Texas SIP approvals; Texas' minor New Source Review program and our approval activities; and, Texas' Prevention of Significant Deterioration (PSD) program can be found in the Technical Support Document (TSD).

    II. EPA's Evaluation of Texas' 2008 O3 and 2010 NO2 NAAQS Infrastructure Submissions

    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 NO2 NAAQS on December 7, 2012, and for the 2008 O3 NAAQS on December 13, 2012. A detailed discussion of our evaluation can be found in the Technical Support Document (TSD) for this action. The TSD can be accessed through www.regulations.gov (e-docket EPA-R06-OAR-2012-0953).

    (A) Emission limits and other control measures: The SIP must include enforceable emission limits and other control measures, means or techniques, schedules for compliance and other related matters as needed to implement, maintain and enforce each of the NAAQS.7

    7 The specific nonattainment area plan requirements of section 110(a)(2)(I) are subject to the timing requirements of section 172, not the timing requirement of section 110(a)(1). Thus, section 110(a)(2)(A) does not require that states submit regulations or emissions limits specifically for attaining the 2008 O3 or NO2 NAAQS. Those SIP provisions are due as part of each state's attainment plan, and will be addressed separately from the requirements of section 110(a)(2)(A). In the context of an infrastructure SIP, we are not evaluating the existing SIP provisions for this purpose. Instead, EPA is only evaluating whether the state's SIP has basic structural provisions for the implementation of the NAAQS.

    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.

    (B) Ambient air quality monitoring/data system: The SIP must provide for establishment and implementation of ambient air quality monitors, collection and analysis of ambient air quality data, and providing the data to EPA upon request.

    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 NO2, as well as other pollutants, in accordance with EPA regulations specifying siting and monitoring requirements. All monitoring data is measured using EPA approved methods and subject to the EPA quality assurance requirements. TCEQ submits all required data to us, following the EPA regulations. The Texas statewide monitoring network was approved into the SIP on May 31, 1972 (37 FR 10842, 10895), was revised on March 7, 1978 (43 FR 9275) and it undergoes recurrent annual review by us.8 In addition, TCEQ conducts a recurrent assessment of its monitoring network every five years, as required by EPA rules. The most recent of these 5-year monitoring network assessments was conducted by TCEQ and approved by us in December of 2010.9 The TCEQ Web site provides the monitor locations and posts past and current concentrations of criteria pollutants measured in the State's network of monitors.10

    8 A copy of the 2015 Annual Air Monitoring Network Plan and our approval letter are included in the docket for this proposed rulemaking.

    9 A copy of TCEQ's 2010 5-year ambient monitoring network assessment and our approval letter are included in the docket for this proposed rulemaking.

    10 See http://www.tceq.texas.gov/airquality/monops/sites/mon_sites.html and http://www17.tceq.texas.gov/tamis/index.cfm?fuseaction=home.welcome.

    (C) Program for enforcement of control measures: The SIP must include the following three elements: (1) A program providing for enforcement of emission limits and other control measures; (2) a program for the regulation of the modification and construction of stationary sources as necessary to protect the applicable NAAQS (i.e., state-wide permitting of minor sources); and (3) a permit program to meet the major source permitting requirements of the CAA (for areas designated as attainment or unclassifiable for the NAAQS in question).

    (1) Enforcement of SIP Measures. As noted earlier, the State statutes provide authority for the TCEQ, its Chairman, and its Executive Director to enforce the requirements of the TCAA, and any regulations, permits, or final compliance orders. These statutes also provide the TCEQ, its Chairman, and its Executive Director with general enforcement powers. Among other things, they can file lawsuits to compel compliance with the statutes and regulations; commence civil actions; issue field citations; conduct investigations of regulated entities; collect criminal and civil penalties; develop and enforce rules and standards related to protection of air quality; issue compliance orders; pursue criminal prosecutions; investigate, enter into remediation agreements; and issue emergency cease and desist orders. The TCAA also provides additional enforcement authorities and funding mechanisms.

    (2) Minor New Source Review. The SIP is required to include measures to regulate construction and modification of stationary sources to protect the NAAQS. The Texas minor NSR permitting requirements are approved as part of the SIP.11

    11 We are not proposing to approve or disapprove the existing Texas minor NSR program to the extent that it may be inconsistent with the regulations governing this program. We have maintained that the CAA does not require that new infrastructure SIP submissions correct any defects in existing EPA-approved provisions of minor NSR programs in order for us to approve the infrastructure SIP for element C (e.g., 76 FR 41076-41079). We believe that a number of states may have minor NSR provisions that are contrary to the existing regulations for this program. The statutory requirements of section 110(a)(2)(C) provide for considerable flexibility in designing minor NSR programs.

    (3) Prevention of Significant Deterioration (PSD) permit program. The Texas PSD portion of the SIP covers all NSR regulated pollutants as well as the requirements for the 2008 O3 and 2010 NO2 NAAQS and has been approved by EPA.

    (D) Interstate and international transport: The requirements for interstate transport of O3 and NO2 emissions are that the SIP contain adequate provisions prohibiting O3 and NO2 emission transport to other states which will (1) contribute significantly to nonattainment of the NAAQS, (2) interfere with maintenance of the NAAQS, (3) interfere with measures required to prevent significant deterioration or (4) interfere with measures to protect visibility (CAA 110(a)(2)(D)(i)). In addition, states must comply with requirements to prevent transport of international air pollution (CAA section 110(a)(2)(D)(ii)).

    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 O3 NAAQS at a later time (110(a)(2)(D)(i)(I)). With regard to emissions which will contribute significantly to nonattainment or interfere with maintenance of the NO2 NAAQS, TCEQ included an interstate transport technical analysis in its submittal. In summary, the analysis found that there are some days where air is transported from Texas to areas in neighboring states that have monitors. However, the reactivity of NO2, coupled with the distance from major Texas areas of NO2 emissions make it highly unlikely that Texas NO2 emissions significantly impact other states. States surrounding Texas are measuring attainment of the NO2 NAAQS; therefore, Texas NO2 sources are not contributing to an exceedance or interfering with maintenance of the NAAQS in neighboring states. We agree with the technical analysis regarding emissions which will contribute significantly to nonattainment or interfere with maintenance of the NO2 NAAQS.

    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 O3 and NO2 in an earlier action (80 FR 74818, December 16, 2014). We will take action on the CAA section 110(a)(2)(D)(i)(II) portion of the Texas O3 and NO2 i-SIP in future rulemaking.

    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 O3 and NO2 i-SIP submittals pertaining to CAA section 110(a)(2)(D)(ii).

    (E) Adequate authority, resources, implementation, and oversight: The SIP must provide for the following: (1) Necessary assurances that the state (and other entities within the state responsible for implementing the SIP) will have adequate personnel, funding, and authority under state or local law to implement the SIP, and that there are no legal impediments to such implementation; (2) requirements relating to state boards; and (3) necessary assurances that the state has responsibility for ensuring adequate implementation of any plan provision for which it relies on local governments or other entities to carry out that portion of the plan. Both elements (A) and (E) address the requirement that there is adequate authority to implement and enforce the SIP and that there are no legal impediments.

    These i-SIP submissions for the 2008 O3 NAAQS and 2010 NO2 NAAQS describe the SIP regulations governing the various functions of personnel within the TCEQ, including the administrative, technical support, planning, enforcement, and permitting functions of the program.

    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 SIP adequately when it authorizes local or other agencies to carry out portions of the plan, the Texas statutes and the SIP designate the TCEQ as the primary air pollution control agency.

    (F) Stationary source monitoring system: The SIP must provide for the establishment of a system to monitor emissions from stationary sources and to submit periodic emission reports. It must require the installation, maintenance, and replacement of equipment, and the implementation of other necessary steps, by owners or operators of stationary sources, to monitor emissions from such sources. The SIP shall also require periodic reports on the nature and amounts of emissions and emissions-related data from such sources, and require that the state correlate the source reports with emission limitations or standards established under the CAA. These reports must be made available for public inspection at reasonable times.

    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.

    (G) Emergency authority: The SIP must provide for authority to address activities causing imminent and substantial endangerment to public health or welfare or the environment and to include contingency plans to implement such authorities as necessary.

    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 NO2 and O3 emissions emitted and monitored statewide, Texas is not required to have contingency plans for the 2008 O3 or 2010 NO2 NAAQS. However, to provide additional protection, the State has general emergency powers to address any possible dangerous air pollution episode if necessary to protect the environment and public health.

    (H) Future SIP revisions: States must have the authority to revise their SIPs in response to changes in the NAAQS, availability of improved methods for attaining the NAAQS, or in response to an EPA finding that the SIP is substantially inadequate to attain the NAAQS.

    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.

    (I) Nonattainment areas: The CAA section 110(a)(2)(I) requires that in the case of a plan or plan revision for areas designated as nonattainment areas, states must meet applicable requirements of part D of the CAA, relating to SIP requirements for designated nonattainment areas.

    In 2012, we designated all areas in the United States as “unclassifiable/attainment” for the one-hour NO2 NAAQS (77 FR 9532). All NO2 monitors in Texas and neighboring states have design values below the 2010 annual NO2 NAAQS, which is 0.053 ppm or 53 ppb and below the one-hour NO2 NAAQS of 100 ppb. Texas currently has two nonattainment areas for the 2008 eight-hour ozone NAAQS; the Houston-Galveston-Brazoria (HGB) marginal nonattainment area and the Dallas-Ft. Worth (DFW) moderate nonattainment area. The rest of the counties in Texas are designated unclassifiable/attainment for the 2008 eight hour O3 NAAQS. For additional information on the Texas ozone nonattainment areas (past and present) please refer to the TSD.

    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.

    (J) Consultation with government officials, public notification, PSD and visibility protection: The SIP must meet the following three CAA requirements: (1) Section 121, relating to interagency consultation regarding certain CAA requirements; (2) section 127, relating to public notification of NAAQS exceedances and related issues; and (3) prevention of significant deterioration of air quality and visibility protection.

    (1) Interagency consultation: As required by the TCAA, there must be a public hearing before the adoption of any regulations or emission control requirements, and all interested persons are given a reasonable opportunity to review the action that is being proposed and to submit data or arguments, either orally or in writing, and to examine the testimony of witnesses from the hearing. In addition, the TCAA provides the TCEQ the power and duty to establish cooperative agreements with local authorities, and consult with other states, the federal government and other interested persons or groups in regard to matters of common interest in the field of air quality control. Furthermore, the Texas PSD SIP rules mandate that the TCEQ shall provide for public participation and notification regarding permitting applications to any other state or local air pollution control agencies, local government officials of the city or county where the source will be located, tribal authorities, and Federal Land Manager (FLMs) whose lands may be affected by emissions from the source or modification. Additionally, the State's PSD SIP rules require the TCEQ to consult with FLMs regarding permit applications for sources with the potential to impact Class I Federal Areas. The SIP also includes a commitment to consult continually with the FLMs on the review and implementation of the visibility program, and the State recognizes the expertise of the FLMs in monitoring and new source review applicability analyses for visibility and has agreed to notify the FLMs of any advance notification or early consultation with a new or modifying source prior to the submission of a permit application. Likewise, the State's Transportation Conformity SIP rules provide for interagency consultation, resolution of conflicts, and public notification.

    (2) Public Notification: The i-SIP submissions from Texas provide the SIP regulatory citations requiring the TCEQ to regularly notify the public of instances or areas in which any NAAQS are exceeded. Included in the SIP are the rules for TCEQ to advise the public of the health hazard associated with such exceedances; and enhance public awareness of measures that can prevent such exceedances and of ways in which the public can participate in the regulatory and other efforts to improve air quality. In addition, as discussed for infrastructure element B above, the TCEQ air monitoring Web site provides quality data for each of the monitoring stations in Texas; this data is provided instantaneously for certain pollutants, such as ozone. The Web site also provides information on the health effects of lead, ozone, particulate matter, and other criteria pollutants.

    (3) PSD and Visibility Protection: The PSD requirements for this element are the same as those addressed under element (C) above. The Texas SIP requirements relating to visibility and regional haze are not affected when we establish or revise a NAAQS. Therefore, we believe that there are no new visibility protection requirements due to the revision of the NAAQS, and consequently there are no newly applicable visibility protection obligations pursuant to infrastructure element (J).

    (K) Air quality and modeling/data: The SIP must provide for performing air quality modeling, as prescribed by EPA, to predict the effects on ambient air quality of any emissions of any NAAQS pollutant, and for submission of such data to EPA upon request.

    The 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.

    (L) Permitting Fees: The SIP must require each major stationary source to pay permitting fees to the permitting authority, as a condition of any permit required under the CAA, to cover the cost of reviewing and acting upon any application for such a permit, and, if the permit is issued, the costs of implementing and enforcing the terms of the permit. The fee requirement applies until a fee program established by the state pursuant to Title V of the CAA, relating to operating permits, is approved by EPA.

    See the discussion for element (E) above for the description of the mandatory collection of permitting fees outlined in the SIP.

    (M) Consultation/participation by affected local entities: The SIP must provide for consultation and participation by local political subdivisions affected by 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.

    IV. Proposed Action

    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 O3 and 2010 NO2 NAAQS. Specifically, we are proposing to approve the following infrastructure elements, or portions thereof: 110(a)(2)(A), (B), (C), (D)(i) (portions pertaining to PSD for O3 and 2010 NO2 and portions pertaining to nonattainment and interference with maintenance for NO2), (D)(ii), (E), (F), (G), (H), (K), (L), and (M). Based upon review of the state's infrastructure SIP submissions and relevant statutory and regulatory authorities and provisions referenced in these submissions or referenced in Texas SIP, we believe that Texas has the infrastructure in place to address the applicable required elements of sections 110(a)(1) and (2) (except otherwise noted) to ensure that the 2008 O3 and 2010 NO2 NAAQS are implemented in the state.

    V. Statutory and Executive Order Reviews

    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 et seq.);

    • 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 et seq.);

    • 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).

    List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Interstate transport of pollution, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Visibility.

    Authority:

    42 U.S.C. 7401 et seq.

    Dated: January 26, 2016. Ron Curry, Regional Administrator, Region 6.
    [FR Doc. 2016-02310 Filed 2-5-16; 8:45 am] BILLING CODE 6560-50-P
    DEPARTMENT OF DEFENSE Defense Acquisition Regulations System 48 CFR Parts 215 and 252 RIN 0750-AI84 Defense Federal Acquisition Regulation Supplement: DFARS Case 2016-D017, Independent Research and Development Expenses AGENCY:

    Defense Acquisition Regulations System, Department of Defense (DoD).

    ACTION:

    Advance notice of proposed rulemaking.

    SUMMARY:

    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.

    DATES:

    Submission of comments: Interested parties should submit written comments to the address shown below on or before April 8, 2016, to be considered in the development of any proposed DFARS rule.

    Public meeting: A public meeting will be held in the General Services Administration (GSA), Central Office Auditorium, 1800 F Street NW., Washington DC, 20405, on March 3, 2016, from 12:00 p.m. to 4:00 p.m., local time. The GSA Auditorium is located on the main floor of the building.

    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, http://www.acq.osd.mil/dpap/dars/IR&D.html, by providing the following information:

    • 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.

    Special Accommodations: The public meeting location is physically accessible to persons with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Mr. Mark Gomersall, telephone 703-602-0302, at least 10 working days prior to the meeting date.

    ADDRESSES:

    Submit comments identified by DFARS Case 2016-D017, using any of the following methods:

    Regulations.gov: http://www.regulations.gov. Submit comments via the Federal eRulemaking portal by entering “DFARS Case 2016-D017” under the heading “Enter keyword or ID” and selecting “Search.” Select the link “Submit a Comment” that corresponds with “DFARS Case 2016-D017.” Follow the instructions provided at the “Submit a Comment” screen. Please include your name, company name (if any), and “DFARS Case 2016-D017” on your attached document.

    Email: [email protected]. Include DFARS Case 2016-D017 in the subject line of the message.

    Fax: 571-372-6099.

    Mail: Defense Acquisition Regulations System, Attn: Mr. Mark Gomersall, OUSD (AT&L) DPAP/DARS, Room 3B941, 3060 Defense Pentagon, Washington, DC 20301-3060.

    Comments received generally will be posted without change to http://www.regulations.gov, including any personal information provided. To confirm receipt of your comment(s), please check www.regulations.gov, approximately two to three days after submission to verify posting (allow 30 days for posting of comments submitted by mail).

    FOR FURTHER INFORMATION CONTACT:

    Mr. Mark Gomersall, telephone 571-372-6099; facsimile 571-372-6101.

    SUPPLEMENTARY INFORMATION:

    I. Background

    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.

    II. Solicitation of Public Comment

    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 means to reduce evaluated bid prices in competitive source selections in a uniform manner that is consistent with the objective of making IR&D an allowable cost.

    List of Subjects in 48 CFR Parts 215 and 252

    Government procurement.

    Jennifer L. Hawes, Editor, Defense Acquisition Regulations System.
    [FR Doc. 2016-02396 Filed 2-5-16; 8:45 am] BILLING CODE 5001-06-P
    DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration 50 CFR Parts 216 and 300 RIN 0648-AX63 Trade Monitoring Procedures for Fishery Products; International Trade in Seafood; Permit Requirements for Importers and Exporters; Public Meeting AGENCY:

    National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

    ACTION:

    Notice of public meeting.

    SUMMARY:

    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.

    DATES:

    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.

    ADDRESSES:

    For information about connecting and system requirements to attend the webinar, visit: http://www.nmfs.noaa.gov/ia/slider_stories/2015/12/itds_proposed_rule.html. Participants are encouraged to use their telephone for the audio portion of the meeting. Instructions for audio access will be on the Web page referenced above and will be shown on the screen before joining the webinar.

    Public comment on the proposed rule should be submitted by February 29, 2016 through www.regulations.gov by accessing docket NOAA-NMFS-2009-0124.

    FOR FURTHER INFORMATION CONTACT:

    Mark Wildman, Office of International Affairs and Seafood Inspection; telephone: (301) 427-8350.

    SUPPLEMENTARY INFORMATION:

    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: http://www.regulations.gov/#!docketDetail;D=NOAA-NMFS-2009-0124. The purpose of the meeting is to inform the public of the proposed requirements for filing entries and exports within the International Trade Data System. Following the presentation of the proposed rule, a question and answer session will be accommodated as time allows. Public comment on the proposed rule should be submitted by February 29, 2016 through www.regulations.gov by accessing docket NOAA-NMFS-2009-0124.

    Special Accommodations

    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.

    Dated: February 2, 2016. Steven Wilson, Acting Director, Office for International Affairs and Seafood Inspection, National Marine Fisheries Service.
    [FR Doc. 2016-02418 Filed 2-5-16; 8:45 am] BILLING CODE 3510-22-P
    DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration 50 CFR Part 679 [Docket No. 150430410-6046-01] RIN 0648-BF05 Fisheries of the Exclusive Economic Zone Off Alaska; Western Alaska Community Development Quota Program AGENCY:

    National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

    ACTION:

    Proposed rule; request for comments.

    SUMMARY:

    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.

    DATES:

    Submit comments on or before March 9, 2016.

    ADDRESSES:

    You may submit comments on this document, identified by NOAA-NMFS-2015-0060, by any of the following methods:

    Electronic Submission: Submit all electronic public comments via the Federal eRulemaking Portal. Go to www.regulations.gov/#!docketDetail;D=NOAA-NMFS-2015-0060, click the “Comment Now!” icon, complete the required fields, and enter or attach your comments.

    Mail: Submit written comments to Glenn Merrill, Assistant Regional Administrator, Sustainable Fisheries Division, Alaska Region NMFS, Attn: Ellen Sebastian. Mail comments to P.O. Box 21668, Juneau, AK 99802-1668.

    Instructions: Comments sent by any other method, to any other address or individual, or received after the end of the comment period, may not be considered by NMFS. All comments received are a part of the public record and will generally be posted for public viewing on www.regulations.gov without change. All personal identifying information (e.g., name, address), confidential business information, or otherwise sensitive information submitted voluntarily by the sender will be publicly accessible. NMFS will accept anonymous comments (enter“N/A” in the required fields if you wish to remain anonymous).

    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 http://www.regulations.gov or from the NMFS Alaska Region Web site at http://alaskafisheries.noaa.gov.

    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 [email protected] or faxed to 202-395-5806.

    FOR FURTHER INFORMATION CONTACT:

    Sally Bibb, 907-586-7389.

    SUPPLEMENTARY INFORMATION:

    Authority for Action

    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, et seq.). Regulations governing U.S. fisheries and implementing the FMP appear at 50 CFR parts 600 and 679.

    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 Federal Register on January 20, 2016, with comments invited through March 21, 2016. Comments may address Amendment 109 or this proposed rule, but must be received by March 21, 2016 to be considered in the approval/disapproval decision on Amendment 109. All comments received by that date, whether specifically directed to Amendment 109, or to this proposed rule, will be considered in the approval/disapproval decision on Amendment 109.

    Background

    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.

    Overview of the CDQ Program

    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.

    CDQ Program Halibut and Groundfish Fisheries

    The CDQ Program is a catch share program that allocates a portion of the BSAI total allowable catch (TAC) for specific crab and groundfish species, a portion of the commercial catch limits assigned by the IPHC, and portions of certain prohibited species catch (PSC) limits to the CDQ Program. These amounts are then further allocated among the six CDQ groups as allocations that may be transferred among the CDQ groups (with the exception of Chinook salmon prohibited species quota (PSQ), which may be transferred to other authorized American Fisheries Act entities). The Magnuson-Stevens Act requires allocations to the CDQ Program of specific percentages of the “total allowable catch, guideline harvest level, or other annual catch limit . . . in each directed fishery” of the BSAI annual catch limits (section 305(i)(1)(B)). The Magnuson-Stevens Act also specifies the percentage allocations among the six CDQ groups (section 305(i)(1)(C)).

    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 http://www.alaskafisheries.noaa.gov/cdq/allocations/annualmatrix2015.pdf.

    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 (e.g., trawl gear is required to effectively harvest pollock and most flatfish species; pot gear is required to effectively harvest crab) or due to the great distance of the fishery from most of the CDQ communities (e.g., Atka mackerel and Pacific ocean perch are primarily harvested in the Aleutian Islands at substantial distance from most CDQ communities).

    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 (i.e., participants in the non-CDQ fisheries). Pacific cod stocks have increased in abundance over the same period that halibut stocks have declined in abundance. In the BSAI, the overfishing level, acceptable biological catch, and subsequent TAC for Pacific cod have generally increased over the past 5 years. As of 2015, Pacific cod abundance is currently higher than at any time since 1995. The Pacific cod biomass is projected to maintain its relatively high abundance or possibly increase in 2016 and future years. More information about Pacific cod and the Pacific cod CDQ fisheries is in Section 3.6 and Section 5.1 of the Analysis.

    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.

    CDQ Program Prohibited Species Catch (PSC) Limits

    In addition to allocations of groundfish, halibut, and crab for harvest, the CDQ groups also receive annual allocations of certain BSAI PSC limits to account for the catch of those prohibited species in the groundfish CDQ fisheries. Prohibited species may be caught by a vessel when fishing for groundfish in the BSAI. A PSC limit is an apportioned, non-retainable amount of fish or crab provided to a groundfish fishery to limit the bycatch of that prohibited species in that particular groundfish fishery.

    The CDQ Program receives annual allocations of the BSAI PSC limits for halibut, Chinook salmon, non-Chinook salmon, red king crab, Chionoecetes (C.) opilio crab, and C. bairdi crab. The annual allocation of a portion of a PSC limit to the CDQ Program is referred to as a PSQ reserve, and the annual allocation of the PSQ reserve among the CDQ groups is referred to as PSQ (see definitions for these terms at § 679.2).

    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.

    Regulatory Constraints on Local Small-Scale Groundfish 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.

    LLP Requirements in the CDQ Fisheries

    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 (e.g., Bering Sea or Aleutian Islands), specific gear (e.g., non-trawl or trawl), and operation type (e.g., catcher vessel or catcher/processor) on LLP licenses. Each license has a maximum length overall (MLOA) designation that restricts the length of the vessel that can be named on that LLP license. In addition, most vessels directed fishing for Pacific cod must be named on an LLP license with a Pacific cod endorsement for the appropriate area, gear, and operation type. Catcher vessels less than 60 ft LOA are not required to have a Pacific cod endorsement on their LLP license to fish for Pacific cod in the BSAI.

    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.

    Observer Coverage Requirements in the CDQ Groundfish and Halibut Fisheries

    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 than or equal to 46 ft LOA. Obtaining an observer for all groundfish CDQ fishing would likely be cost prohibitive for the CDQ groups and vessel owners given the revenue for these small vessels. Section 3.6.6.2 of the Analysis provides additional detail on the costs of placing observers on board small vessels in the BSAI.

    Need for the Proposed Action

    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.

    LLP Exemption

    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 (i.e., non-trawl gear), and operation type (i.e., catcher vessel) that could be used on the seven catcher vessels greater than 32 ft LOA and less than or equal to 46 ft LOA that do not have LLP licenses are assigned to other non-CDQ vessels actively fishing in the BSAI. Based on the information available, it does not appear that LLP licenses with the necessary endorsements for these seven small vessels are available for transfer. Therefore, the exemption to LLP requirements for catcher vessels that are less than or equal to 46 ft LOA would provide additional groundfish harvest opportunities to the owners and operators of vessels based in CDQ communities. Additional detail about the limitations to obtaining an appropriately endorsed LLP license for the catcher vessels less than 46 ft LOA using hook-and-line gear is provided in Section 3.6.6.1 of the Analysis.

    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 vessel operator, and that each vessel operator maintain a legible copy of the LLP exemption letter on board the vessel at all times when fishing for groundfish CDQ. Maintaining a legible copy of the LLP exemption letter on board the vessel would provide documentation that the vessel is exempt from the LLP requirements, should the vessel be boarded by the U.S. Coast Guard or NMFS' Office of Law Enforcement. Although the CDQ vessel registration list of vessels eligible for the LLP exemption would be available on NMFS' Web site, vessel boardings can occur in areas with no access to the internet. In these cases, the LLP exemption letter would provide initial documentation that the vessel is exempt from the LLP, which could later be confirmed by checking the CDQ vessel registration list. More information about the CDQ vessel registration system and the LLP exemption letter is in the section below titled “The Proposed Rule.”

    Observer Coverage

    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.

    Catch Accounting and Fisheries Management

    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.

    Catch Accounting

    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 Proposed Rule

    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).

    LLP Exemption

    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 LLP exemption would not be required to obtain and carry an LLP license when they are groundfish CDQ fishing if certain vessel registration requirements are met prior to groundfish CDQ fishing.

    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 http://alaskafisheries.noaa.gov.

    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.

    Catch Accounting and Fishery Monitoring Requirements

    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 small hook-and-line catcher vessel groundfish CDQ fishery, the CDQ group would be required to transfer halibut PSQ from its halibut PSQ to its small catcher vessel halibut PSC limit through a CDQ Transfer Request under § 679.5(n). CDQ groups that do not want to have a local small-scale groundfish CDQ fishery would not have to transfer any halibut PSQ to this account. Each CDQ group would, in collaboration with NMFS, decide the appropriate amount of halibut PSQ to transfer to the small catcher vessel halibut PSC limit based on the amount of groundfish CDQ it wanted to allocate to its small hook-and-line catcher vessel groundfish CDQ fishery and the expected use of halibut PSC in that fishery.

    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 Federal Register authorizing a CDQ group to conduct such fishing. In deciding whether to authorize groundfish CDQ fishing by these vessels, NMFS would consider whether a CDQ group has sufficient halibut in its small catcher vessel halibut PSC limit to support groundfish CDQ fishing by these catcher vessels.

    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 Federal Register prohibiting groundfish CDQ fishing by the small hook-and-line catcher vessels fishing for that CDQ group. NMFS would be responsible for issuing fishing closures to the small hook-and-line catcher vessel groundfish CDQ fisheries to maintain halibut PSC by these vessels within the small catcher vessel halibut PSC limit established by a CDQ group. NMFS would manage these fisheries to stay within the applicable CDQ groups' halibut PSC amount to the best of its ability, and would manage the small hook-and-line catcher vessel groundfish CDQ fishery conservatively to ensure that these PSC limits are not exceeded.

    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.

    Observer Coverage

    The proposed rule would add paragraph (a)(1)(i)(D) to § 679.51 and revise § 679.51(a)(2)(i)(C)(2) to place catcher vessels less than or equal to 46 ft LOA that are using hook-and-line gear when groundfish CDQ fishing in the partial observer coverage category. This new paragraph is proposed as paragraph (a)(1)(i)(D) because a separate proposed rule implementing Amendment 112 to the FMP and Amendment 102 to the Fishery Management Plan for Groundfish of the Gulf of Alaska is proposing to add a new paragraph (a)(1)(i)(C) to § 679.51 (see 80 FR 81262; December 29, 2015).

    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 (http://alaskafisheries.noaa.gov/sustainablefisheries/observers/).

    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.

    Other Regulatory Change

    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.

    Classification

    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.

    Initial Regulatory Flexibility Analysis

    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 ADDRESSES). A summary of the analysis follows.

    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 directed regulated small entities or reduced reporting, recordkeeping, or compliance costs more than the preferred alternative that would be implemented by this proposed rule.

    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.

    Collection-of-Information Requirements

    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 ADDRESSES above, and email to [email protected], or fax to (202) 395-5806.

    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.

    List of Subjects in 50 CFR Part 679

    Alaska, Fisheries, Reporting and recordkeeping requirements.

    Dated: February 2, 2016. Samuel D. Rauch III, Deputy Assistant Administrator for Regulatory Programs, National Marine Fisheries Service.

    For the reasons set out in the preamble, 50 CFR part 679 is proposed to be amended as follows:

    PART 679—FISHERIES OF THE EXCLUSIVE ECONOMIC ZONE OFF ALASKA 1. The authority citation for 50 CFR part 679 continues to read as follows: Authority:

    16 U.S.C. 773 et seq.; 1801 et seq.; 3631 et seq.; Pub. L. 108-447; Pub. L. 111-281

    2. In § 679.4 a. In paragraph (k)(2)(iv) remove the words “license, or” and add in their place “license” and in paragraph k)(2)(v) remove “Area” and add in its place “Area, or”. b. Add paragraph (k)(2)(vi):

    The addition to read as follows:

    § 679.4 Permits.

    (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.

    § 679.4 [Amended]
    7. At each of the locations shown in the “Location” column, remove the phrase indicated in the “Remove” column and replace it with the phrase indicated in the “Add” column for the number of times indicated in the “Frequency” column. Location Remove Add Frequency § 679.4(k)(2)(iv) license; or license; 1 § 679.4(k)(2)(v) Area Area; or 1 3. In § 679.5, add paragraph (m) to read as follows:
    § 679.5 Recordkeeping and reporting (R&R).

    (m) CDQ Vessel Registration—(1) Registration. The representative for a CDQ group must register each vessel that is to receive the exemption from the LLP license requirements at § 679.4(k)(2)(vi) through the CDQ vessel registration system available on the NMFS Alaska Region Web site (http://alaskafisheries.noaa.gov). The CDQ group representative must log into the CDQ vessel registration system and provide the information required on the computer screen. NMFS will add each vessel successfully registered to the CDQ vessel registration list on the NMFS Alaska Region Web site at http://alaskafisheries.noaa.gov.

    (2) Responsibility. The CDQ group representative must successfully complete vessel registration through the CDQ vessel registration system before the vessel may be used to conduct groundfish CDQ fishing under § 679.32(c)(3)(iii) without an LLP license. By using the CDQ group's NMFS ID and password and submitting the vessel registration request, the CDQ group representative certifies that all information is true, correct, and complete.

    (3) LLP exemption letter. The CDQ vessel registration system will provide the CDQ group representative with an LLP exemption letter documenting that the registered vessel is exempt from the LLP when groundfish CDQ fishing. The CDQ group representative must provide a copy of the LLP exemption letter to the operator of the registered vessel named in the LLP exemption letter. The operator of the registered vessel named in the LLP exemption letter must maintain a legible copy of the LLP exemption letter on board the registered vessel at all times when that vessel is groundfish CDQ fishing.

    (4) Removing a vessel from the CDQ vessel registration list. A CDQ group representative may remove a vessel from the CDQ vessel registration system by logging into the online system and following the applicable instructions. A CDQ group representative may remove a registered vessel from the CDQ vessel registration list at any time but must certify at the time of removal that the vessel operator had been given notice by the CDQ group that the vessel is going to be removed from the list and that the vessel is not groundfish CDQ fishing at the time of removal. A vessel that is successfully removed from the CDQ vessel registration list is no longer exempt from the LLP requirements under § 679.4(k).

    4. In § 679.7, add paragraphs (d)(8) and (9) to read as follows:
    § 679.7 Prohibitions.

    (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.

    5. In § 679.32, a. Add a new first sentence to paragraphs (c)(3)(i)(D) and (c)(3)(ii)(D); and b. Add paragraph (c)(3)(iii) to read as follows:
    § 679.32 Groundfish and halibut CDQ catch monitoring.

    (c) * * *

    (3) * * *

    (i) * * *

    (D) Observed catcher vessels using nontrawl gear. This paragraph applies to all observed catcher vessels using nontrawl gear, except those catcher vessels regulated under paragraph (c)(3)(iii) of this section.* * *

    (ii) * * *

    (D) Observed catcher vessels using nontrawl gear. This paragraph applies to all observed catcher vessels using nontrawl gear, except those catcher vessels regulated under paragraph (c)(3)(iii) of this section.* * *

    (iii) Groundfish CDQ fishing by catcher vessels less than or equal to 46 ft LOA using hook-and-line gear—(A) Applicability. Regulations in this paragraph apply to the operators of catcher vessels less than or equal to 46 ft (14.0 m) LOA using hook-and-line gear when groundfish CDQ fishing and to the CDQ groups authorizing the operators of these vessels to harvest groundfish CDQ or halibut CDQ.

    (B) Halibut CDQ or halibut IFQ. If any halibut CDQ or halibut IFQ are retained during a fishing trip on board a vessel described in paragraph (c)(3)(iii)(A) of this section, the following requirements apply:

    (1) The vessel operator must retain all legal-size halibut caught during that entire fishing trip.

    (2) The vessel operator must have sufficient halibut IFQ or halibut CDQ available to account for the catch of all legal-size halibut caught during the entire fishing trip.

    (3) 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 must provide adequate halibut CDQ to this vessel operator to account for all of the legal-size halibut caught by the vessel during the entire fishing trip.

    (C) Halibut PSC. If halibut CDQ or halibut IFQ are not retained during a fishing trip on board a vessel described in paragraph (c)(3)(iii)(A) of this section, the following requirements apply:

    (1) The vessel operator must discard all halibut caught during the fishing trip.

    (2) Small catcher vessel halibut PSC limit. The CDQ group representative may transfer halibut from a CDQ group's halibut PSQ to its small catcher vessel halibut PSC limit. To do so, the CDQ representative must submit a transfer request using the procedures described in § 679.5(n). In reviewing a request to transfer halibut PSQ to a CDQ group's small catcher vessel halibut PSC limit, NMFS will consider whether the amount of halibut to be transferred to the small catcher vessel halibut PSC limit is sufficient to support groundfish CDQ fishing by the catcher vessels that the CDQ group plans to authorize to conduct groundfish CDQ fishing. The transfer is not effective until approved by NMFS. The CDQ group representative also may transfer halibut from a CDQ group's small catcher vessel halibut PSC limit back to its halibut PSQ by submitting a transfer request using the procedures described in § 679.5(n). In reviewing a request to transfer halibut from the small catcher vessel halibut PSC limit back to the CDQ group's halibut PSQ, NMFS will 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.

    (3) Fishery closures. Directed fishing for groundfish CDQ, except sablefish CDQ managed under paragraph (c)(1) of this section, by catcher vessels less than or equal to 46 ft LOA using hook-and-line gear is prohibited unless the Regional Administrator publishes notification in the Federal Register authorizing such directed fishing. In deciding whether to authorize directed fishing, NMFS will consider whether a CDQ group has sufficient halibut in its small catcher vessel halibut PSC limit to support directed fishing for groundfish CDQ by these catcher vessels. Upon determining that a CDQ group's small catcher vessel halibut PSC limit has been or will be reached, the Regional Administrator will publish notification in the Federal Register prohibiting directed fishing for all groundfish CDQ species, except sablefish CDQ, by catcher vessels less than or equal to 46 ft LOA using hook-and-line gear fishing for that CDQ group. If the estimated halibut PSC by vessels described in paragraph (c)(3)(iii)(A) of this section exceeds the balance of the small catcher vessel halibut PSC limit on December 31 of any year, and if the CDQ group has remaining halibut PSQ on that date, NMFS will 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 will make the determination about whether such an administrative transfer is necessary after data from the fishing year is finalized.

    6. In § 679.51: a. Remove § 679.51 introductory text and paragraph (f); b. Add paragraph (a)(1)(i)(D); and c. Revise paragraph (a)(2)(i)(C)(2) to read as follows:
    § 679.51 Observer requirements for vessels and plants.

    (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) * * *

    (2) Using trawl gear or hook-and-line gear when groundfish CDQ fishing (see § 679.2), except for catcher vessels less than or equal to 46 ft LOA using hook-and-line gear when groundfish CDQ fishing under § 679.32(c)(3)(iii); or

    [FR Doc. 2016-02319 Filed 2-5-16; 8:45 am] BILLING CODE 3510-22-P
    81 25 Monday, February 8, 2016 Notices DEPARTMENT OF AGRICULTURE Animal and Plant Health Inspection Service [Docket No. APHIS-2016-0007] Secretary's Advisory Committee on Animal Health; Meeting AGENCY:

    Animal and Plant Health Inspection Service, USDA.

    ACTION:

    Notice of meeting.

    SUMMARY:

    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.

    DATES:

    The meeting will be held February 23, 24, and 25, 2016, from 9 a.m. to 5 p.m. central standard time.

    ADDRESSES:

    The meeting will be held at the Marriott Dallas/Addison Quorum, 14901 Dallas Parkway, Dallas, TX 75254.

    FOR FURTHER INFORMATION CONTACT:

    Mrs. R.J. Cabrera, Designated Federal Officer, VS, APHIS, 4700 River Road Unit 34, Riverdale, MD 20737; phone (301) 851-3478; email: [email protected].

    SUPPLEMENTARY INFORMATION:

    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 (http://www.aphis.usda.gov/animalhealth/sacah). Members of the public may also join the meeting via teleconference in “listen-only” mode. Participants who wish to listen in on the teleconference may do so by dialing 1-800-619-4086 and then entering the public passcode, 2236462#.

    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 [email protected] or mailed to the person listed in this notice under FOR FURTHER INFORMATION CONTACT. Statements filed with the Committee must include the name of the individual listed under FOR FURTHER INFORMATION CONTACT, the docket number listed in this notice, and specify that they pertain to the February 2016 Committee meeting.

    This notice of meeting is given pursuant to section 10 of the Federal Advisory Committee Act (5 U.S.C. App. 2).

    Done in Washington, DC, this 3rd day of February 2016. Kevin Shea, Administrator, Animal and Plant Health Inspection Service.
    [FR Doc. 2016-02464 Filed 2-5-16; 8:45 am] BILLING CODE 3410-34-P
    DEPARTMENT OF AGRICULTURE Food Safety and Inspection Service [Docket No. FSIS-2015-0045] Notice of Request To Renew an Approved Information Collection; Importation and Transportation of Meat, Poultry, and Egg Products AGENCY:

    Food Safety and Inspection Service, USDA.

    ACTION:

    Notice and request for comments.

    SUMMARY:

    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.

    DATES:

    Submit comments on or before April 8, 2016.

    ADDRESSES:

    FSIS invites interested persons to submit comments on this information collection. Comments may be submitted by one of the following methods:

    Federal eRulemaking Portal: This Web site provides the ability to type short comments directly into the comment field on this Web page or attach a file for lengthier comments. Go to http://www.regulations.gov. Follow the on-line instructions at that site for submitting comments.

    Mail, including CD-ROMs, etc.: Send to Docket Clerk, U.S. Department of Agriculture, Food Safety and Inspection Service, Docket Clerk, Patriots Plaza 3, 1400 Independence Avenue SW., Mailstop 3782, Room8-163A, Washington, DC 20250-3700.

    Hand- or courier-delivered submittals: Deliver to Patriots Plaza 3, 355 E Street SW., Room 8-163A, Washington, DC 20250-3700.

    Instructions: All items submitted by mail or electronic mail must include the Agency name and docket number FSIS-2015-0045. Comments received in response to this docket will be made available for public inspection and posted without change, including any personal information, to http://www.regulations.gov.

    Docket: For access to background documents or comments received, go to the FSIS Docket Room at Patriots Plaza 3, 355 E Street SW., Room 8-164, Washington, DC 20250-3700 between 8:00 a.m. and 4:30 p.m., Monday through Friday.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    Title: Importation and Transportation of Meat, Poultry, and Egg Products.

    OMB Control Number: 0583-0094.

    Type of Request: Renewal of an approved information collection.

    Abstract: FSIS has been delegated the authority to exercise the functions of the Secretary of Agriculture (7 CFR 2.18, 2.53) as specified in the Federal Meat Inspection Act (FMIA) (21 U.S.C. 601, et seq.), the Poultry Products and Inspection Act (PPIA) (21 U.S.C. 451, et seq.), and the Egg Products Inspection Act (EPIA) (21 U.S.C. 1031, et seq.). FSIS protects the public by verifying that meat, poultry, and egg products are safe, wholesome, not adulterated, and correctly labeled.

    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.

    Estimate of Burden: FSIS estimates that it takes each respondent an average of 29.6 hours per year to complete the foreign inspection certificates, pre-stamp documentation, and documentation required to transport meat and poultry shipments.

    Respondents: Importers, establishments, foreign governments.

    Estimated No. of Respondents: 136.

    Estimated No. of Annual Responses per Respondent: 650.

    Estimated Total Annual Burden on Respondents: 4,026 hours.

    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.

    Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of FSIS's functions, including whether the information will have practical utility; (b) the accuracy of FSIS's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques, or other forms of information technology. Comments may be sent to both FSIS, at the addresses provided above, and the Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20253.

    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.

    Additional Public Notification

    Public awareness of all segments of rulemaking and policy development is important. Consequently, FSIS will announce this Federal Register publication on-line through the FSIS Web page located at: http://www.fsis.usda.gov/federal-register.

    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, Federal Register notices, FSIS public meetings, and other types of information that could affect or would be of interest to our constituents and stakeholders. The Update is available on the FSIS Web page. Through the Web page, FSIS is able to provide information to a much broader, more diverse audience. In addition, FSIS offers an email subscription service which provides automatic and customized access to selected food safety news and information. This service is available at: http://www.fsis.usda.gov/subscribe. Options range from recalls to export information, regulations, directives, and notices. Customers can add or delete subscriptions themselves, and have the option to password protect their accounts.

    USDA Non-Discrimination Statement

    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.

    How To File a Complaint of Discrimination

    To file a complaint of discrimination, complete the USDA Program Discrimination Complaint Form, which may be accessed online at http://www.ocio.usda.gov/sites/default/files/docs/2012/Complain_combined_6_8_12.pdf, or write a letter signed by you or your authorized representative.

    Send your completed complaint form or letter to USDA by mail, fax, or email:

    Mail: U.S. Department of Agriculture, Director, Office of Adjudication, 1400 Independence Avenue SW., Washington, DC 20250-9410.

    Fax: (202) 690-7442.

    Email: [email protected].

    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).

    Done at Washington, DC, on: February 2, 2016. Alfred V. Almanza, Acting Administrator.
    [FR Doc. 2016-02326 Filed 2-5-16; 8:45 am] BILLING CODE 3410-DM-P
    DEPARTMENT OF AGRICULTURE Forest Service 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 AGENCY:

    Forest Service, USDA.

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    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 Federal Register.

    ADDRESSES:

    Robin Dale, Alaska Region Group Leader for Appeals, Litigation, FOIA & Records; Forest Service, Alaska Region; P.O. Box 21628; Juneau, Alaska 99802-1628.

    FOR FURTHER INFORMATION CONTACT:

    Robin Dale; Alaska Region Group Leader for Administrative Reviews, Litigation, FOIA & Records; (907) 586-9344.

    SUPPLEMENTARY INFORMATION:

    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:

    Alaska Regional Office

    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.

    Chugach National Forest

    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.

    Tongass National Forest

    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.

    Dated: January 15, 2016. Beth G. Pendleton, Regional Forester.
    [FR Doc. 2016-02361 Filed 2-5-16; 8:45 am] BILLING CODE 3410-11-M
    DEPARTMENT OF AGRICULTURE Forest Service Idaho Panhandle Resource Advisory Committee; Meeting AGENCY:

    Forest Service, USDA.

    ACTION:

    Notice of meeting.

    SUMMARY:

    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: http://www.fs.usda.gov/main/ipnf/workingtogether/advisorycommittees.

    DATES:

    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 FOR FURTHER INFORMATION CONTACT.

    ADDRESSES:

    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 SUPPLEMENTARY INFORMATION. All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at the Idaho Panhandle national Forests Supervisor's Office in Coeur d'Alene, Idaho. Please call ahead to facilitate entry into the building.

    FOR FURTHER INFORMATION CONTACT:

    Shoshana Cooper, RAC Coordinator, by phone at 208-765-7211 or via email at [email protected].

    Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8:00 a.m. and 8:00 p.m., Eastern Standard Time, Monday through Friday.

    SUPPLEMENTARY INFORMATION:

    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 [email protected], or via facsimile to 208-765-7426.

    Meeting Accommodations: If you are a person requiring reasonable accommodation, please make requests in advance for sign language interpreting, assistive listening devices or other reasonable accommodation for access to the facility or proceedings by contacting the person listed in the section titled FOR FURTHER INFORMATION CONTACT. All reasonable accommodation requests are managed on a case by case basis.

    Dated: February 1, 2016. Mary Farnsworth, Forest Supervisor.
    [FR Doc. 2016-02435 Filed 2-5-16; 8:45 am] BILLING CODE 3411-15-P
    DEPARTMENT OF AGRICULTURE Rural Utilities Service Information Collection Activity; Comment Request AGENCY:

    Rural Utilities Service, USDA.

    ACTION:

    Notice and request for comments.

    SUMMARY:

    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).

    DATES:

    Comments on this notice must be received by April 8, 2016.

    FOR FURTHER INFORMATION CONTACT:

    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: [email protected].

    SUPPLEMENTARY INFORMATION:

    The Office of Management and Budget's (OMB) regulation (5 CFR 1320) implementing provisions of the Paperwork Reduction Act of 1995 (Pub. L. 104-13) requires that interested members of the public and affected agencies have an opportunity to comment on information collection and recordkeeping activities (see 5 CFR 1320.8(d)). This notice identifies an information collection that RUS is submitting to OMB for extension.

    Comments are invited on: (a) Whether this collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility; (b) the accuracy of the Agency's estimate of the burden of the proposed collection of information including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology. Comments may be sent to: Thomas P. Dickson, Acting Director, Program Development and Regulatory Analysis, USDA Rural Development, STOP 1522, 1400 Independence Avenue SW., Washington, DC 20250-1522. FAX: (202) 720-8435.

    Title: Emergency and Imminent Community Water Assistance Grants, 7 CFR 1778.

    OMB Control Number: 0572-0110.

    Type of Request: Extension of a currently approved information collection.

    Abstract: Rural Utilities Service (RUS), an agency delivering the U.S. Department of Agriculture (USDA) administers Emergency and Imminent Community Water Assistance Grants pursuant to 7 CFR 1778 and awards grants to qualified rural communities that have experienced a significant decline in quality or quantity of water or expect such a decline to be imminent. Grants under this RUS program may be made to public bodies and private nonprofit corporations serving rural areas. Public bodies include counties, cities, townships, incorporated towns and villages, boroughs, authorities, districts, and other political subdivisions of a state. Public bodies also include Indian Tribes on Federal and State reservations and other Federally-recognized Indian tribal groups in rural areas. Applicants will provide information to be collected as part of the application and grant process through documentation, certifications, or completed application forms. These procedures are codified at 7 CFR part 1778.

    Estimate of Burden: Public reporting for this collection of information is estimated to average 4 hours per response.

    Respondents: Not-for-profit Institutions.

    Estimated Number of Respondents: 100.

    Estimated Total Annual Burden on Respondents: 400 hours.

    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: [email protected].

    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.

    Dated: February 2, 2016. Brandon McBride, Administrator, Rural Utilities Service.
    [FR Doc. 2016-02462 Filed 2-5-16; 8:45 am] BILLING CODE P
    DEPARTMENT OF COMMERCE International Trade Administration [A-570-832] Pure Magnesium From the People's Republic of China: Preliminary Results of Antidumping Duty Administrative Review; 2014-2015 AGENCY:

    Enforcement and Compliance, International Trade Administration, Department of Commerce.

    SUMMARY:

    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/TMM”).1 The Department preliminarily finds that TMI/TMM did not have reviewable entries during the POR. The Department invites interested parties to comment on these preliminary results.

    1 The Department initiated the instant review on both TMM and TMI. See Initiation of Antidumping and Countervailing Duty Administrative Reviews, 80 FR 37588, 37593 (July 1, 2015) (“Initiation Notice”). In the 2011-2012 review of the order, the Department determined TMM and TMI to be collapsed and treated as a single company for purposes of the proceeding. See Pure Magnesium From the People's Republic of China: Final Results of Antidumping Duty Administrative Review; 2011-2012, 79 FR 94 (January 2, 2014) and accompanying Issues and Decision Memorandum at Comment 5. As this collapsing determination remains unchallenged in this review, the preliminary results of this review cover the single TMM/TMI company. This is consistent with the Department's treatment of the single TMM/TMI company under identical circumstance in the prior 2013-2014 no shipments administrative review (see Pure Magnesium from the People's Republic of China: Final Results of Antidumping Duty Administrative Review; 2013-2014, 80 FR 26541 (May 8, 2015)).

    DATES:

    Effective Date: February 8, 2016.

    FOR FURTHER INFORMATION CONTACT:

    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.

    Scope of the Order

    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 (i.e., length or diameter) of one inch or less, secondary magnesium (which has pure primary magnesium content of less than 50% by weight), and remelted magnesium whose pure primary magnesium content is less than 50% by weight.

    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.

    Background

    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, 2015.2 On May 29, 2015, U.S. Magnesium LLC (“U.S. Magnesium”), a domestic producer and Petitioner in the underlying investigation of this case, made a timely request that the Department conduct an administrative review of TMI and TMM.3 On July 1, 2015, in accordance with section 751(a) of the Tariff Act of 1930, as amended (“the Act”), the Department published in the Federal Register a notice of initiation of this antidumping duty administrative review.4 On July 23 and 28, 2015, TMM and TMI, respectively, separately submitted letters to the Department certifying that they did not export pure magnesium for consumption in the United States during the POR.5

    2See Antidumping or Countervailing Duty Order, Finding, or Suspended Investigation; Opportunity To Request Administrative Review, 80 FR 24898 (May 1, 2015).

    3See letter from U.S. Magnesium, “Pure Magnesium From the People's Republic of China: Request for Administrative Review,” dated May 29, 2015.

    4See Initiation Notice.

    5See Letter from TMM, “Pure Magnesium from the People's Republic of China; A-570-832; Certification of No Sales by Tianjin Magnesium Metal, Co., Ltd.,” dated July 23, 2015; see also letter from TMI, “Pure Magnesium from {t}he People's Republic of China; A-570-832; Certification of No Sales by Tianjin Magnesium International, Co., Ltd.,” dated July 28, 2014. We note this letter was timely filed and received on the record of the instant review on July 28, 2015, and, as such, the July 28, 2014, date of this letter was likely a typographical error.

    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.6 This information indicates that there were no entries of subject merchandise during the POR exported by TMI or TMM. In addition, on December 5, 2015, the Department notified CBP that it was in receipt of a no-shipment certification from TMI and TMM and requested CBP to report any contrary information within 10 days.7 CBP did not report any contrary information.

    6See Memorandum to the File, “2014-2015 Administrative Review of Pure Magnesium from the People's Republic of China: U.S. Customs and Border Protection Data,” dated January 21, 2016 (“CBP Data Query”).

    7See Memorandum to the File, “Transmit No Shipment Inquiry to the File,” dated December 4, 2015, containing Customs Message #527305 (“CBP No Shipment Inquiry”).

    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, 2016.8

    8See Memorandum to the File from Ron Lorentzen, Acting A/S for Enforcement & Compliance, “Tolling of Administrative Deadlines As a Result of the Government Closure During Snowstorm Jonas,” dated January 27, 2016.

    Preliminary Determination of No Shipments

    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; 9 CBP did not provide any evidence that contradicts TMI or TMM's claim of no shipments,10 and no interested party provided comment concerning the results of the CBP query.

    9See CBP Data Query.

    10See CBP No Shipment Inquiry.

    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.11

    11See Non-Market Economy Antidumping Proceedings: Assessment of Antidumping Duties, 76 FR 65694 (October 24, 2011) and the “Assessment Rates” section, below.

    Public Comment

    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 https://access.trade.gov, and to all parties in the Central Records Unit, room B8024 of the main Department of Commerce building. An electronically-filed request must be received successfully in its entirety by ACCESS by 5:00 p.m. Eastern Standard Time, within 30 days after the date of publication of this notice.12 Requests should contain: (1) The party's name, address and telephone number; (2) the number of participants; and (3) a list of issues to be discussed. Issues raised in the hearing will be limited to those raised in the respective case briefs. The Department intends to issue the final results of this administrative review, including the results of its analysis of the issues raised in any written briefs, not later than 120 days after the date of publication of this notice, pursuant to section 751(a)(3)(A) of the Act.

    12See 19 CFR 351.310(c).

    Assessment Rates

    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 (i.e., at that exporter's rate) will be liquidated at the PRC-wide rate.13

    13 For a full discussion of this practice, see Non-Market Economy Antidumping Proceedings: Assessment of Antidumping Duties, 76 FR 65694 (October 24, 2011).

    Cash Deposit Requirements

    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.

    Notification to Importers

    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.

    Dated: February 1, 2016. Paul Piquado, Assistant Secretary for Enforcement and Compliance.
    [FR Doc. 2016-02425 Filed 2-5-16; 8:45 am] BILLING CODE 3510-DS-P
    DEPARTMENT OF COMMERCE International Trade Administration [C-122-854] Supercalendered Paper From Canada: Initiation of Expedited Review of the Countervailing Duty Order AGENCY:

    Enforcement and Compliance, International Trade Administration, Department of Commerce.

    SUMMARY:

    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).

    DATES:

    Effective date: February 8, 2016.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    Background

    On December 10, 2015, the Department published the countervailing duty order on supercalendered paper from Canada.1 On December 15 and 16, 2015, the Department received requests from Catalyst and Irving, respectively, to conduct an expedited review of this countervailing duty order.2 Irving supplemented its request on January 6, 2015.3 Catalyst and Irving, companies that were not selected for individual examination during the investigation, made these requests pursuant to 19 CFR 351.214(k).

    1See Supercalendered Paper From Canada: Countervailing Duty Order, 80 FR 76668 (December 10, 2015).

    2See letter from Catalyst, “Supercalendered Paper from Canada: Catalyst's Request for Expedited Review,” (December 15, 2015). See also letter from Irving, “Supercalendered Paper from Canada: Expedited Review Request of Irving Paper Limited Pursuant to 19 CFR 351.214(k),” (December 16, 2015).

    3See letter from Irving, “Supercalendered Paper from Canada: Supplement to Expedited Review Request of Irving Paper Limited Pursuant to 19 CFR 351.214(k),” (January 6, 2015).

    Initiation of Expedited Review

    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.4 As specified by 19 CFR 351.214(k)(3)(i), the period of review will be the same as the original period of investigation, i.e., January 1, 2014, through December 31, 2014.

    4 Under 19 CFR 351.214(k)(i)(2), this period may be extended to 300 days.

    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 de minimis, as provided in 19 CFR 351.214(k)(3)(iv).

    Interested parties must submit applications for disclosure under administrative protective orders in accordance with 19 CFR 351.305 and 351.306.

    Dated: February 1, 2016. Gary Taverman, Associate Deputy Assistant Secretary for Antidumping and Countervailing Duty Operations.
    [FR Doc. 2016-02397 Filed 2-5-16; 8:45 am] BILLING CODE 3510-DS-P
    DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration Fisheries of the U.S. Caribbean; Southeast Data, Assessment and Review (SEDAR); U.S. Caribbean Data-Limited Species AGENCY:

    National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

    ACTION:

    Notice of SEDAR 46 Review Workshop for U.S. Caribbean Data-Limited Species.

    SUMMARY:

    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.

    DATES:

    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 SUPPLEMENTARY INFORMATION.

    ADDRESSES:

    Meeting address: The SEDAR 46 Review Workshop will be held at the Mayfair Hotel and Spa, 3000 Florida Avenue, Miami, FL 33133; telephone: (800) 321-2211.

    SEDAR address: 4055 Faber Place Drive, Suite 201, N. Charleston, SC 29405.

    FOR FURTHER INFORMATION CONTACT:

    Julie Neer, SEDAR Coordinator; telephone: (843) 571-4366 or toll free (866) SAFMC-10; fax: (843) 769-4520; email: [email protected].

    SUPPLEMENTARY INFORMATION:

    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.

    Special Accommodations

    This meeting is physically accessible to people with disabilities. Requests for auxiliary aids should be directed to the Council office (see ADDRESSES) 3 days prior to the meeting.

    Note:

    The times and sequence specified in this agenda are subject to change.

    Authority:

    16 U.S.C. 1801 et seq.

    Dated: February 3, 2016. Tracey L. Thompson, Acting Deputy Director, Office of Sustainable Fisheries, National Marine Fisheries Service.
    [FR Doc. 2016-02393 Filed 2-5-16; 8:45 am] BILLING CODE 3510-22-P
    DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration Mid-Atlantic Fishery Management Council (MAFMC); Public Meeting AGENCY:

    National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

    ACTION:

    Notice; public meeting.

    SUMMARY:

    The Mid-Atlantic Fishery Management Council will hold a public meeting of the Scientific Uncertainty Subcommittee of the Scientific and Statistical Committee.

    DATES:

    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 SUPPLEMENTARY INFORMATION.

    ADDRESSES:

    The meeting will at the DoubleTree by Hilton Baltimore-BWI Airport; 890 Elkridge Landing Rd, Linthicum Heights, MD 21090.

    Council address: Mid-Atlantic Fishery Management Council, 800 N. State Street, Suite 201, Dover, DE 19901; telephone: (302) 674-2331 or on their Web site at www.mafmc.org.

    FOR FURTHER INFORMATION CONTACT:

    Christopher M. Moore, Ph.D., Executive Director, Mid-Atlantic Fishery Management Council, telephone: (302) 526-5255.

    SUPPLEMENTARY INFORMATION:

    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.

    Special Accommodations

    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.

    Dated: February 2, 2016. Tracey L. Thompson, Acting Deputy Director, Office of Sustainable Fisheries, National Marine Fisheries Service.
    [FR Doc. 2016-02293 Filed 2-5-16; 8:45 am] BILLING CODE 3510-22-P
    DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration RIN 0648-XD224 Marine Mammals; File No. 18537 AGENCY:

    National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

    ACTION:

    Notice; receipt of application for permit amendment.

    SUMMARY:

    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.

    DATES:

    Written, telefaxed, or email comments must be received on or before March 9, 2016.

    ADDRESSES:

    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, https://apps.nmfs.noaa.gov, and then selecting File No. 18537 from the list of available applications.

    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 [email protected]. Please include the File No. in the subject line of the email comment.

    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.

    FOR FURTHER INFORMATION CONTACT:

    Rosa L. González or Amy Sloan, (301) 427-8401.

    SUPPLEMENTARY INFORMATION:

    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 et seq.), the regulations governing the taking and importing of marine mammals (50 CFR part 216), the Endangered Species Act of 1973, as amended (16 U.S.C. 1531 et seq.), the regulations governing the taking, importing, and exporting of endangered and threatened species (50 CFR 222-226), and the Fur Seal Act of 1966, as amended (16 U.S.C. 1151 et seq.).

    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 (Zalophus californianus), and northern fur (Callorhinus ursinus), harbor (Phoca vitulina), spotted (Phoca largha), ribbon (Histriophoca fasciata), ringed (Phoca hispida hispida), and bearded (Erignathus barbatus) seals during research activities, and annual unintentional mortality of 5 Steller sea lions from the Western Distinct Population Segment (wDPS) and 10 Steller sea lions from the Eastern DPS. See tables in permit for numbers of takes by species, stock and activity. The permit is valid through August 31, 2019.

    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 et seq.), an initial determination has been made that the activities proposed are consistent with the Preferred Alternative in the Final Programmatic Environmental Impact Statement for Steller Sea Lion and Northern Fur Seal Research (NMFS 2007), and that issuance of the permit would not have a significant adverse impact on the human environment.

    Concurrent with the publication of this notice in the Federal Register, NMFS is forwarding copies of this application to the Marine Mammal Commission and its Committee of Scientific Advisors.

    Dated: February 2, 2016. Dr. Perry F. Gayaldo, Deputy Director, Office of Protected Resources, National Marine Fisheries Service.
    [FR Doc. 2016-02385 Filed 2-5-16; 8:45 am] BILLING CODE 3510-22-P
    DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration RIN 0648-XB160 Marine Mammals; File Nos. 16193 and 17157 AGENCY:

    National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

    ACTION:

    Notice; issuance of permit amendments.

    SUMMARY:

    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.

    ADDRESSES:

    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.

    FOR FURTHER INFORMATION CONTACT:

    Jennifer Skidmore or Amy Sloan, (301) 427-8401.

    SUPPLEMENTARY INFORMATION:

    On December 8, 2015, notices were published in the Federal Register (File No. 16193-01, 80 FR 76276; and File No. 17157-02, 80 FR 76278) that requests for amendments had been submitted by the above-named applicants to amend their permits to receive, import, and export specimens from marine mammals for scientific research. The requested permit amendments have been issued under the authority of the Marine Mammal Protection Act of 1972, as amended (16 U.S.C. 1361 et seq.), the regulations governing the taking and importing of marine mammals (50 CFR part 216), the Endangered Species Act of 1973, as amended (ESA; 16 U.S.C. 1531 et seq.), and the regulations governing the taking, importing, and exporting of endangered and threatened species (50 CFR parts 222-226).

    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 (Inia geoffrensis) annually.

    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 (Balaenoptera musculus), sei (B. borealis), minke (B. acutorostrata), humpback (Megaptera novaeangliae), gray (Eschrichtius robustus), bowhead (Balaena mysticetus), fin (B. physalus), and sperm (Physeter macrocephalus). The samples may be obtained from natural history museums as well as from collections in Barrow, Alaska, of bowhead whale subsistence harvests.

    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 et seq.), a final determination has been made that the activity proposed is categorically excluded from the requirement to prepare an environmental assessment or environmental impact statement.

    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.

    Dated: February 2, 2016. Perry F. Gayaldo, Deputy Director, Office of Protected Resources, National Marine Fisheries Service.
    [FR Doc. 2016-02384 Filed 2-5-16; 8:45 am] BILLING CODE 3510-22-P
    COMMODITY FUTURES TRADING COMMISSION Technology Advisory Committee Meeting Notice AGENCY:

    Commodity Futures Trading Commission.

    ACTION:

    Notice of meeting.

    SUMMARY:

    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.

    DATES:

    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.

    ADDRESSES:

    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: [email protected]. Please use the title “Technology Advisory Committee” in any written statement you submit. Any statements submitted in connection with the committee meeting will be made available to the public, including publication on the CFTC Web site, www.cftc.gov.

    FOR FURTHER INFORMATION CONTACT:

    Ward P. Griffin, TAC Designated Federal Officer, Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st Street NW., Washington, DC 20581, (202) 418-5425.

    SUPPLEMENTARY INFORMATION:

    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 connect to a live, listen-only audio feed. Call-in participants should be prepared to provide their first name, last name, and affiliation. Instructions for domestic and international calls will be posted on the CFTC's Web site, http://www.cftc.gov, on the page for the meeting, under Related Documents. After the meeting, a transcript of the meeting will be published through a link on the CFTC's Web site, http://www.cftc.gov. All written submissions provided to the CFTC in any form will also be published on the CFTC's Web site. Persons requiring special accommodations to attend the meeting because of a disability should notify the contact person above.

    Authority:

    5 U.S.C. app. 2 § 10(a)(2).

    Dated: February 3, 2016. Christopher J. Kirkpatrick, Secretary of the Commission.
    [FR Doc. 2016-02375 Filed 2-5-16; 8:45 am] BILLING CODE 6351-01-P
    CONSUMER PRODUCT SAFETY COMMISSION [Docket No. CPSC-2016-0002] Notice of Availability: CPSC's Draft 2016-2020 Strategic Plan AGENCY:

    U.S. Consumer Product Safety Commission.

    ACTION:

    Notice of availability.

    SUMMARY:

    The Consumer Product Safety Commission (“CPSC”) has drafted a Strategic Plan for 2016-2020. CPSC seeks comments from the public on the draft plan.

    DATES:

    Submit comments by March 9, 2016.

    ADDRESSES:

    You may submit comments, identified by Docket No. CPSC-2016-0002, by any of the following methods:

    Electronic Submissions: Submit electronic comments to the Federal eRulemaking Portal at: http://www.regulations.gov. Follow the instructions for submitting comments. The Commission does not accept comments submitted by electronic mail (email), except through www.regulations.gov. The Commission encourages you to submit electronic comments by using the Federal eRulemaking Portal, as described above.

    Written Submissions: Submit written submissions by mail/hand delivery/courier to: Office of the Secretary, Consumer Product Safety Commission, Room 820, 4330 East-West Highway, Bethesda, MD 20814; telephone (301) 504-7923.

    Instructions: All submissions received must include the agency name and docket number for this notice. All comments received may be posted without change, including any personal identifiers, contact information, or other personal information provided, to:http://www.regulations.gov. Do not submit confidential business information, trade secret information, or other sensitive or protected information that you do not want to be available to the public. If furnished at all, such information should be submitted in writing.

    Docket: For access to the docket to read background documents or comments received, go to: http://www.regulations.gov, and insert the docket number CPSC-2016-0002, into the “Search” box, and follow the prompts.

    FOR FURTHER INFORMATION CONTACT:

    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: [email protected].

    SUPPLEMENTARY INFORMATION:

    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: http://www.cpsc.gov/en/About-CPSC/Agency-Reports/Performance-and-Budget/.

    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 ADDRESSES section of this notice.

    Dated: February 3, 2016. Todd A. Stevenson, Secretary, Consumer Product Safety Commission.
    [FR Doc. 2016-02360 Filed 2-5-16; 8:45 am] BILLING CODE 6355-01-P
    ENVIRONMENTAL PROTECTION AGENCY [FRL-9928-97-OEI] Agency Information Collection Activities OMB Responses AGENCY:

    Environmental Protection Agency (EPA).

    ACTION:

    Notice.

    SUMMARY:

    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 et seq.). 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 EPA regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.

    FOR FURTHER INFORMATION CONTACT:

    Courtney Kerwin (202) 566-1669, or email at [email protected] and please refer to the appropriate EPA Information Collection Request (ICR) Number.

    SUPPLEMENTARY INFORMATION: OMB Responses to Agency Clearance Requests OMB Approvals

    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.

    Comment Filed

    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.

    Courtney Kerwin, Acting Director, Collections Strategies Division.
    [FR Doc. 2016-02359 Filed 2-5-16; 8:45 am] BILLING CODE 6560-50-P
    ENVIRONMENTAL PROTECTION AGENCY [EPA-HQ-OPPT-2013-6077; FRL-9941-65] Receipt of Test Data Under the Toxic Substances Control Act AGENCY:

    Environmental Protection Agency (EPA).

    ACTION:

    Notice.

    SUMMARY:

    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 SUPPLEMENTARY INFORMATION.

    FOR FURTHER INFORMATION CONTACT:

    For technical information contact: Kathy Calvo, Chemical Control Division (7405M), Office of Pollution Prevention and Toxics, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; telephone number: (202) 564-8089; email address: [email protected].

    For general information contact: The TSCA-Hotline, ABVI-Goodwill, 422 South Clinton Ave., Rochester, NY 14620; telephone number: (202) 554-1404; email address: [email protected].

    SUPPLEMENTARY INFORMATION:

    I. Chemical Substances and/or Mixtures

    Information about the following chemical substances and/or mixtures is provided in Unit IV.: D-erythro-hex-2-enonic acid, gamma-lactone, monosodium salt (CAS RN 6381-77-7).

    II. Federal Register Publication Requirement

    Section 4(d) of TSCA (15 U.S.C. 2603(d)) requires EPA to publish a notice in the Federal Register reporting the receipt of test data submitted pursuant to test rules promulgated under TSCA section 4 (15 U.S.C. 2603).

    III. Docket Information

    A docket, identified by the docket identification (ID) number EPA-HQ-OPPT-2013-0677, has been established for this Federal Register document that announces the receipt of data. Upon EPA's completion of its quality assurance review, the test data received will be added to the docket for the TSCA section 4 test rule that required the test data. Use the docket ID number provided in Unit IV. to access the test data in the docket for the related TSCA section 4 test rule.

    The docket for this Federal Register document and the docket for each related TSCA section 4 test rule is available electronically at http://www.regulations.gov or in person at the Office of Pollution Prevention and Toxics Docket (OPPT Docket), Environmental Protection Agency Docket Center (EPA/DC), West William Jefferson Clinton Bldg., Rm. 3334, 1301 Constitution Ave. NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the OPPT Docket is (202) 566-0280. Please review the visitor instructions and additional information about the docket available at http://www.epa.gov/dockets.

    IV. Test Data Received

    This unit contains the information required by TSCA section 4(d) for the test data received by EPA.

    D-erythro-hex-2-enonic acid, gamma-lactone, monosodium salt (CAS RN 6381-77-7)

    1. Chemical Use(s): Antioxidant in food applications for which the vitamin activity of ascorbic acid (Vitamin C) is not required. Specifically, the compound is most frequently used to develop and retain the coloring and taste in meat products. It is also used for seafood products, fruit, and vegetable preservation, in beverages, and as a developing agent in photographic applications.

    2. Applicable Test Rule: Chemical testing requirements for second group of high production volume chemicals (HPV2), 40 CFR 799-5087.

    3. Test Data Received: The following listing describes the nature of the test data received. The test data will be added to the docket for the applicable TSCA section 4 test rule and can be found by referencing the docket ID number provided. EPA reviews of test data will be added to the same docket upon completion.

    Aquatic Toxicity Studies (Fish) (Daphnid) (C1). The docket ID number assigned to this data is EPA-HQ-OPPT-2007-0531.

    Authority:

    15 U.S.C. 2601 et seq.

    Dated: January 27, 2016. Maria J. Doa, Director, Chemical Control Division, Office of Pollution Prevention and Toxics.
    [FR Doc. 2016-02412 Filed 2-5-16; 8:45 am] BILLING CODE 6560-50-P
    FEDERAL COMMUNICATIONS COMMISSION [OMB 3060-0017] Information Collection Being Submitted for Review and Approval to the Office of Management and Budget AGENCY:

    Federal Communications Commission.

    ACTION:

    Notice and request for comments.

    SUMMARY:

    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.

    DATES:

    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.

    ADDRESSES:

    Direct all PRA comments to Nicholas A. Fraser, OMB, via email [email protected]; and to Cathy Williams, FCC, via email [email protected] and to [email protected]. Include in the comments the OMB control number as shown in the SUPPLEMENTARY INFORMATION section below.

    FOR FURTHER INFORMATION CONTACT:

    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 http://www.reginfo.gov/public/do/PRAMain, (2) look for the section of the Web page called “Currently Under Review,” (3) click on the downward-pointing arrow in the “Select Agency” box below the “Currently Under Review” heading, (4) select “Federal Communications Commission” from the list of agencies presented in the “Select Agency” box, (5) click the “Submit” button to the right of the “Select Agency” box, (6) when the list of FCC ICRs currently under review appears, look for the OMB control number of this ICR and then click on the ICR Reference Number. A copy of the FCC submission to OMB will be displayed.

    SUPPLEMENTARY INFORMATION:

    OMB Control Number: 3060-0017.

    Title: Application for Media Bureau Audio and Video Service Authorization, FCC 2100, Schedule D.

    Form Number: FCC Form 2100, Schedule D.

    Type of Review: Revision of a currently approved collection.

    Respondents: Business or other for profit entities; Not for profit institutions; State, local or Tribal government.

    Number of Respondents/Responses: 550 respondents; 550 responses.

    Estimated Hours per Response: 1.5 hours per response.

    Frequency of Response: One time reporting requirement; On occasion reporting requirement.

    Total Annual Burden: 825 hours.

    Total Annual Cost: $66,446.

    Obligation to Respond: Required to obtain benefits. The statutory authority for this information collection is contained in sections 154(i), 301, 303, 307, 308 and 309 of the Communications Act of 1934, as amended.

    Nature and Extend of Confidentiality: There is no need for confidentiality with this collection of information.

    Privacy Act Assessment: No impact(s).

    Needs and Uses: In FCC 15-175, low power television and TV translator stations be permitted to share a channel. FCC Form 2100, Schedule D will be used to license channel sharing between these types of stations. FCC Form 2100, Schedule D was modified to allow applicants to propose that their stations be licensed on a shared basis.

    Federal Communications Commission. Gloria J. Miles, Federal Liaison Officer, Office of the Secretary.
    [FR Doc. 2016-02328 Filed 2-5-16; 8:45 am] BILLING CODE 6712-01-P
    FEDERAL COMMUNICATIONS COMMISSION [DA 16-98] Disability Advisory Committee; Announcement of Next Meeting AGENCY:

    Federal Communications Commission.

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    The Committee's next meeting will take place on Tuesday, February 23, 2016, from 9:00 a.m. to 3:30 p.m. (EST).

    ADDRESSES:

    Federal Communications Commission, 445 12th Street SW., Washington, DC 20554, in the Commission Meeting Room.

    FOR FURTHER INFORMATION CONTACT:

    Elaine Gardner, Consumer and Governmental Affairs Bureau: 202-418-0581 (voice); email: [email protected]; or Suzy Rosen Singleton, Alternate DAC Designated Federal Officer, Consumer and Governmental Affairs Bureau: 202-510-9446 (VP/voice), at the same email address: [email protected].

    SUPPLEMENTARY INFORMATION:

    The Committee was established in December 2014 to make recommendations to the Commission on a wide array of disability matters within the jurisdiction of the Commission, and to facilitate the participation of people with disabilities in proceedings before the Commission. The Committee is organized under, and operated in accordance with, the provisions of the Federal Advisory Committee Act (FACA). The Committee held its first meeting on March 17, 2015.

    At its 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 [email protected]. The meeting site is fully accessible to people using wheelchairs or other mobility aids. Sign language interpreters, open captioning, and assistive listening devices will be provided on site. Other reasonable accommodations for people with disabilities are available upon request. If making a request for an accommodation, please include a description of the accommodation you will need and tell us how to contact you if we need more information. Make your request as early as possible by sending an email to [email protected] or calling the Consumer and Governmental Affairs Bureau at 202-418-0530 (voice), 202-418-0432 (TTY). Last minute requests will be accepted, but may be impossible to fill. The meeting will be webcast with open captioning, at: www.fcc.gov/live.

    To request materials in accessible formats for people with disabilities (Braille, large print, electronic files, audio format), send an email to [email protected] or call the Consumer and Governmental Affairs Bureau at (202) 418-0530 (voice), (202) 418-0432 (TTY).

    Federal Communications Commission. Karen Peltz Strauss, Deputy Chief, Consumer and Governmental Affairs Bureau.
    [FR Doc. 2016-02323 Filed 2-5-16; 8:45 am] BILLING CODE 6712-01-P
    FEDERAL COMMUNICATIONS COMMISSION [OMB 3060-0700] Information Collection Being Reviewed by the Federal Communications Commission AGENCY:

    Federal Communications Commission.

    ACTION:

    Notice and request for comments.

    SUMMARY:

    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.

    DATES:

    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.

    ADDRESSES:

    Direct all PRA comments to Cathy Williams, FCC, via email [email protected] and to [email protected].

    FOR FURTHER INFORMATION CONTACT:

    For additional information about the information collection, contact Cathy Williams at (202) 418-2918.

    SUPPLEMENTARY INFORMATION:

    OMB Control: 3060-0700.

    Title: Open Video Systems Provisions, FCC Form 1275.

    Form Number: FCC Form 1275.

    Type of Review: Extension of a currently approved collection.

    Respondents: Business or other for-profit entities; and State, Local or Tribal Government.

    Number of Respondents and Responses: 280 respondents; 4,672 respondents.

    Frequency of Response: Recordkeeping requirement; Third party disclosure requirement; On occasion reporting requirement.

    Estimated Time per Response: 0.25 to 20 hours.

    Total Annual Burden: 9,855 hours.

    Total Annual Costs: None.

    Privacy Impact Assessment: No impact(s).

    Obligation to Respond: Required to obtain or retain benefits. The statutory authority for this collection is contained in Section 302 of the Communications Act of 1934, as amended.

    Nature and Extent of Confidentiality: There is no need for confidentiality with this collection of information.

    Needs and Uses: Section 302 of the 1996 Telecommunications Act provides for specific entry options for telephone companies wishing to enter the video programming marketplace, one option being to provide cable service over an “open video system” (“OVS”). The rule sections that are covered by this collection relate to OVS.

    Federal Communications Commission. Gloria J. Miles, Federal Register Liaison Officer, Office of the Secretary.
    [FR Doc. 2016-02327 Filed 2-5-16; 8:45 am] BILLING CODE 6712-01-P
    FEDERAL RESERVE SYSTEM Formations of, Acquisitions by, and Mergers of Bank Holding Companies

    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 et seq.) (BHC Act), Regulation Y (12 CFR part 225), and all other applicable statutes and regulations to become a bank holding company and/or to acquire the assets or the ownership of, control of, or the power to vote shares of a bank or bank holding company and all of the banks and nonbanking companies owned by the bank holding company, including the companies listed below.

    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:

    1. Wintrust Financial Corporation, Rosemont, Illinois; to merge with Generations Bancorp, Inc. and thereby indirectly acquire Foundations Bank, both in Pewaukee, Wisconsin.

    Board of Governors of the Federal Reserve System, February 3, 2016. Michael J. Lewandowski, Associate Secretary of the Board.
    [FR Doc. 2016-02374 Filed 2-5-16; 8:45 am] BILLING CODE 6210-01-P
    FEDERAL RESERVE SYSTEM Notice of Proposals To Engage in or To Acquire Companies Engaged in Permissible Nonbanking Activities

    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 de novo, or to acquire or control voting securities or assets of a company, including the companies listed below, that engages either directly or through a subsidiary or other company, in a nonbanking activity that is listed in § 225.28 of Regulation Y (12 CFR 225.28) or that the Board has determined by Order to be closely related to banking and permissible for bank holding companies. Unless otherwise noted, these activities will be conducted throughout the United States.

    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. Merchants Bancorp, Carmel, Indiana; to engage in extending credit and servicing loans through a joint venture, Arclight Financial, LLC, Cinnaminson, New Jersey, pursuant to section 225.28(b)(1).

    Board of Governors of the Federal Reserve System, February 3, 2016. Michael J. Lewandowski, Assistant Secretary of the Board.
    [FR Doc. 2016-02376 Filed 2-5-16; 8:45 am] BILLING CODE 6210-01-P
    FEDERAL RESERVE SYSTEM Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company

    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 [email protected]:

    1. VHS Grantor Retained Annuity Trust #1, Martha Sigmon Spurlock, as trustee, and Charles Kenneth Spurlock, Jr., both of Big Stone Gap, Virginia, and Rachel Sigmon West, Harrogate, Tennessee, all acting in concert; to acquire additional voting shares of Commercial Bancgroup, Inc., and thereby indirectly acquire voting shares of Commercial Bank, both in Harrogate, Tennessee.

    Board of Governors of the Federal Reserve System, February 3, 2016. Michael J. Lewandowski, Associate Secretary of the Board.
    [FR Doc. 2016-02373 Filed 2-5-16; 8:45 am] BILLING CODE 6210-01-P
    DEPARTMENT OF DEFENSE GENERAL SERVICES ADMINISTRATION NATIONAL AERONAUTICS AND SPACE ADMINISTRATION [OMB Control No. 9000-0097; Docket 2016-0053; Sequence 6] Information Collection; Taxpayer Identification Number Information AGENCIES:

    Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

    ACTION:

    Notice of request for public comments regarding an extension to an existing OMB clearance.

    SUMMARY:

    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.

    DATES:

    Submit comments on or before April 8, 2016.

    ADDRESSES:

    Submit comments identified by Information Collection 9000-0097, Taxpayer Identification Number Information, by any of the following methods:

    Regulations.gov: http://www.regulations.gov.

    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.

    Mail: General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405. ATTN: Ms. Flowers/IC 9000-0097, Taxpayer Identification Number Information.

    Instructions: Please submit comments only and cite Information Collection 9000-0097, Taxpayer Identification Number Information, in all correspondence related to this collection. Comments received generally will be posted without change to http://www.regulations.gov, including any personal and/or business confidential information provided. To confirm receipt of your comment(s), please check www.regulations.gov, approximately two to three days after submission to verify posting (except allow 30 days for posting of comments submitted by mail).

    FOR FURTHER INFORMATION CONTACT:

    Mr. Curtis E. Glover, Sr., Procurement Analyst, Contract Policy Division, GSA, 202-501-1448 or email at [email protected].

    SUPPLEMENTARY INFORMATION:

    A. Purpose

    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.

    B. Annual Reporting Burden

    Respondents: 39,428.

    Responses per Respondent: 3.

    Total Responses: 118,284.

    Hours per Response: .10.

    Total Burden Hours: 11,828.

    C. Public Comments

    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 No. 9000-0097, Taxpayer Identification Number Information, in all correspondence.

    Dated: February 3, 2016. Lorin S. Curit, Director, Federal Acquisition Policy Division, Office of Governmentwide Acquisition Policy, Office of Acquisition Policy, Office of Governmentwide Policy.
    [FR Doc. 2016-02407 Filed 2-5-16; 8:45 am] BILLING CODE 6820-EP-P
    DEPARTMENT OF DEFENSE GENERAL SERVICES ADMINISTRATION NATIONAL AERONAUTICS AND SPACE ADMINISTRATION [OMB Control No. 9000-0159; Docket 2016-0053; Sequence 4] Information Collection; Central Contractor Registration AGENCIES:

    Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

    ACTION:

    Notice of request for public comments regarding an extension to an existing OMB clearance.

    SUMMARY:

    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.

    DATES:

    Submit comments on or before April 8, 2016.

    ADDRESSES:

    Submit comments identified by Information Collection 9000-0159, Central Contractor Registration, by any of the following methods:

    Regulations.gov: http://www.regulations.gov. Submit comments via the Federal eRulemaking portal by searching for the OMB control number. Select the link “Submit a Comment” that corresponds with “Information Collection 9000-0159, Central Contractor Registration.” Follow the instructions provided at the “Submit a Comment” screen. Please include your name, company name (if any), and “Information Collection 9000-0159, Central Contractor Registration” on your attached document.

    Mail: General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405. ATTN: Ms. Flowers/IC 9000-0159, Central Contractor Registration.

    Instructions: Please submit comments only and cite Information Collection 9000-0159, Central Contractor Registration, in all correspondence related to this collection. Comments received generally will be posted without change to http://www.regulations.gov, including any personal and/or business confidential information provided. To confirm receipt of your comment(s), please check www.regulations.gov, approximately two to three days after submission to verify posting (except allow 30 days for posting of comments submitted by mail).

    FOR FURTHER INFORMATION CONTACT:

    Mr. Curtis E. Glover, Sr., Procurement Analyst, Office of Governmentwide Policy, GSA, 202-501-1448, or via email at [email protected].

    SUPPLEMENTARY INFORMATION:

    A. Purpose

    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.

    B. Annual Reporting Burden

    Respondents: 110,350.

    Responses per Respondent: 1.

    Annual Responses: 110,350.

    Hours per Response: 1.7141.

    Total Burden Hours: 189,151.

    C. Public Comments

    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.

    Dated: February 3, 2016. Lorin S. Curit, Director, Federal Acquisition Policy Division, Office of Governmentwide Acquisition Policy, Office of Acquisition Policy, Office of Governmentwide Policy.
    [FR Doc. 2016-02408 Filed 2-5-16; 8:45 am] BILLING CODE 6820-EP-P
    DEPARTMENT OF DEFENSE GENERAL SERVICES ADMINISTRATION NATIONAL AERONAUTICS AND SPACE ADMINISTRATION [OMB Control No. 9000-0175; Docket 2016-0053; Sequence 5] Information Collection; Use of Project Labor Agreements for Federal Construction Projects AGENCIES:

    Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

    ACTION:

    Notice of request for public comments regarding a new OMB information clearance.

    SUMMARY:

    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.

    DATES:

    Submit comments on or before April 8, 2016.

    ADDRESSES:

    Submit comments identified by Information Collection 9000-0175, Use of Project Labor Agreements for Federal Construction Projects, by any of the following methods:

    Regulations.gov: http://www.regulations.gov.

    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.

    Mail: General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405. ATTN: Ms. Flowers/IC 9000-0175, Use of Project Labor Agreements for Federal Construction Projects.

    Instructions: Please submit comments only and cite Information Collection 9000-0175, Use of Project Labor Agreements for Federal Construction Projects, in all correspondence related to this collection. Comments received generally will be posted without change to http://www.regulations.gov, including any personal and/or business confidential information provided. To confirm receipt of your comment(s), please check www.regulations.gov, approximately two to three days after submission to verify posting (except allow 30 days for posting of comments submitted by mail).

    FOR FURTHER INFORMATION CONTACT:

    Mr. Edward Loeb, Procurement Analyst, Office of Governmentwide Acquisition Policy, at telephone 202-501-0650 or via email to [email protected].

    SUPPLEMENTARY INFORMATION: A. Purpose

    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, producing labor-management stability, and ensuring compliance with laws and regulations governing safety and health, equal employment opportunity, labor and employment standards, and other matters; and,

    (2) Be consistent with law.

    B. Annual Reporting Burden

    Respondents: 70.

    Responses per Respondent: 1.

    Annual Responses: 70.

    Hours per Response: 1.

    Total Burden Hours: 70.

    C. Public Comments

    Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the 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 No. 9000-0175, Use of Project Labor Agreements for Federal Construction Projects, in all correspondence.

    Dated: February 3, 2016. Lorin S. Curit, Director, Federal Acquisition Policy Division, Office of Governmentwide Acquisition Policy, Office of Acquisition Policy, Office of Governmentwide Policy.
    [FR Doc. 2016-02450 Filed 2-5-16; 8:45 am] BILLING CODE 6820-EP-P
    DEPARTMENT OF DEFENSE GENERAL SERVICES ADMINISTRATION NATIONAL AERONAUTICS AND SPACE ADMINISTRATION [OMB Control No. 9000-0060; Docket 2016-0053; Sequence 5] Information Collection; Accident Prevention Plans and Recordkeeping AGENCY:

    Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

    ACTION:

    Notice of request for an extension of an information collection requirement regarding an existing OMB clearance.

    SUMMARY:

    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.

    DATES:

    Submit comments on or before April 8, 2016.

    ADDRESSES:

    Submit comments identified by Information Collection 9000-0060, Accident Prevention Plans and Recordkeeping by any of the following methods:

    • Regulations.gov: http://www.regulations.gov.

    • Regulations.gov: http://www.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.

    Instructions: Please submit comments only and cite Information Collection 9000-0060, Accident Prevention Plans and Recordkeeping, in all correspondence related to this collection. Comments received generally will be posted without change tohttp://www.regulations.gov, including any personal and/or business confidential information provided. To confirm receipt of your comment(s), please check www.regulations.gov , approximately two to three days after submission to verify posting (except allow 30 days for posting of comments submitted by mail).

    FOR FURTHER INFORMATION CONTACT:

    Mr. Curtis E. Glover, Sr., Procurement Analyst, Contract Policy Division, GSA, telephone 202-501-1448 or email at [email protected].

    SUPPLEMENTARY INFORMATION: A. Purpose

    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.

    B. Annual Reporting Burden

    Respondents: 215.

    Responses per Respondent: 1.

    Annual Responses: 215.

    Hours per Response: 22.

    Total Burden Hours: 4,730.

    C. Public Comments

    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.

    Obtaining Copies of Proposals: Requesters may obtain a copy of the information collection documents from the General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405, telephone 202-501-4755. Please cite OMB Control No. 9000-0060, Accident Prevention Plans and Recordkeeping, in all correspondence.

    Dated: February 3,2016. Lorin S. Curit, Director, Federal Acquisition Policy Division, Office of Governmentwide Acquisition Policy, Office of Acquisition Policy, Office of Governmentwide Policy.
    [FR Doc. 2016-02406 Filed 2-5-16; 8:45 am] BILLING CODE 6820-EP-P
    GENERAL SERVICES ADMINISTRATION [Notice-CECANF-2016-03; Docket No. 2016-0004; Sequence No. 3] Commission To Eliminate Child Abuse and Neglect Fatalities; Announcement of Meetings AGENCY:

    Commission to Eliminate Child Abuse and Neglect Fatalities, General Services Administration.

    ACTION:

    Meetings notice.

    SUMMARY:

    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.

    DATES:

    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).

    ADDRESSES:

    CECANF will convene these meetings via conference call. Submit comments, identified by “Notice-CECANF-2016-03,” by either of the following methods:

    Regulations.gov: http://www.regulations.gov. Submit comments via the Federal eRulemaking portal by searching for “Notice-CECANF-2016-03.” Select the link “Comment Now” that corresponds with “Notice-CECANF-2016-03.” Follow the instructions provided on the screen. Please include your name, organization name (if any), and “Notice-CECANF-2016-03” on your attached document.

    Mail: General Services Administration, 1800 F Street NW., Room 7003D, Washington, DC 20405, Attention: Tom Hodnett (CD) for CECANF.

    Instructions: Please submit comments only and cite “Notice-CECANF-2016-03” in all correspondence related to this notice. Comments received generally will be posted without change to http://www.regulations.gov, including any personal and/or business confidential information provided. To confirm receipt of your comment(s), please check http://www.regulations.gov, approximately two to three days after submission to verify posting (except allow 30 days for posting of comments submitted by mail).

    FOR FURTHER INFORMATION CONTACT:

    Visit the CECANF Web site at https://eliminatechildabusefatalities.sites.usa.gov/ or contact Patricia Brincefield, Communications Director, at 202-818-9596, General Services Administration, 1800 F Street NW., Room 7003D, Washington, DC 20405, Attention: Tom Hodnett (CD) for CECANF.

    SUPPLEMENTARY INFORMATION:

    Background: CECANF was established to develop a national strategy and recommendations for reducing fatalities resulting from child abuse and neglect.

    Agenda: Commission members will deliberate on the final report.

    Attendance at the Meetings: Individuals interested in participating by teleconference should dial 1-888-289-4573 and then enter 6966324#. Detailed meeting minutes will be posted within 90 days of the meeting. Members of the public will not have the opportunity to ask questions or otherwise participate in the meeting.

    However, members of the public wishing to comment should follow the steps detailed under the heading Addresses in this publication or contact the Commission via the CECANF Web site at https://eliminatechildabusefatalities.sites.usa.gov/contact-us/.

    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.

    Dated: February 1, 2016. Karen White, Executive Assistant.
    [FR Doc. 2016-02452 Filed 2-5-16; 8:45 am] BILLING CODE 6820-34-P
    DEPARTMENT OF DEFENSE GENERAL SERVICES ADMINISTRATION NATIONAL AERONAUTICS AND SPACE ADMINISTRATION [OMB Control No. 9000-0053; Docket 2015-0055; Sequence 25] Submission for OMB Review; Permits, Authorities, or Franchises AGENCIES:

    Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

    ACTION:

    Notice of request for public comments regarding an extension of a previously existing OMB clearance.

    SUMMARY:

    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 Federal Register at 80 FR 70217 on November 13, 2015. No comments were received.

    DATES:

    Submit comments on or before March 9, 2016.

    ADDRESSES:

    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:

    Regulations.gov: http://www.regulations.gov. Submit comments via the Federal eRulemaking portal by searching the OMB control number. Select the link “Submit a Comment” that corresponds with “Information Collection 9000-0053, Permits, Authorities, or Franchises”. Follow the instructions provided at the “Submit a Comment” screen. Please include your name, company name (if any), and “Information Collection 9000-0053, Permits, Authorities, or Franchises” on your attached document.

    Mail: General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405. ATTN: Ms. Flowers/IC 9000-0053, Permits, Authorities, or Franchises.

    Instructions: Please submit comments only and cite “Information Collection 9000-0053, Permits, Authorities, or Franchises,” in all correspondence related to this collection. Comments received generally will be posted without change to http://www.regulations.gov, including any personal and/or business confidential information provided. To confirm receipt of your comment(s), please check www.regulations.gov, approximately two to three days after submission to verify posting (except allow 30 days for posting of comments submitted by mail).

    FOR FURTHER INFORMATION CONTACT:

    Mr. Michael O. Jackson, Procurement Analyst, Office of Governmentwide Acquisition Policy, GSA 202-208-4949 or email [email protected].

    SUPPLEMENTARY INFORMATION: A. Purpose

    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.

    B. Annual Reporting Burden

    Respondents: 255.

    Responses per Respondent: 1.

    Annual Responses: 255.

    Hours per Response: 0.5.

    Total Burden Hours: 128.

    C. Public Comments

    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.

    Obtaining Copies of Proposals: Requesters may obtain a copy of the information collection documents from the General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405 telephone 202-501-4755.

    Please cite OMB Control No. 9000-0053, Permits, Authorities, or Franchises, in all correspondence.

    Dated: February 3, 2016. Lorin S. Curit, Director, Federal Acquisition Policy Division, Office of Governmentwide Acquisition Policy, Office of Acquisition Policy, Office of Governmentwide Policy.
    [FR Doc. 2016-02451 Filed 2-5-16; 8:45 am] BILLING CODE 6820-EP-P
    DEPARTMENT OF DEFENSE GENERAL SERVICES ADMINISTRATION NATIONAL AERONAUTICS AND SPACE ADMINISTRATION [OMB Control No. 9000-0057; Docket 2015-0055; Sequence 24] Submission for OMB Review; Evaluation of Export Offers AGENCIES:

    Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

    ACTION:

    Notice of request for public comments regarding an extension to an existing OMB clearance.

    SUMMARY:

    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 Federal Register at 80 FR 65761 on October 27, 2015. No comments were received.

    DATES:

    Submit comments on or before March 9, 2016.

    ADDRESSES:

    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:

    Regulations.gov: http://www.regulations.gov. Submit comments via the Federal eRulemaking portal by inputting “Information Collection 9000-0057, Evaluation of Export Offers” under the heading “Enter Keyword or ID” and selecting “Search”. Select the link “Submit a Comment” that corresponds with “Information Collection 9000-0057, Evaluation of Export Offers”. Follow the instructions provided at the “Submit a Comment” screen. Please include your name, company name (if any), and “Information Collection 9000-0057, Evaluation of Export Offers” on your attached document.

    Mail: General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405. ATTN: Ms. Flowers/IC 9000-0057, Evaluation of Export Offers.

    Instructions: Please submit comments only and cite Information Collection “Information Collection 9000-0057, Evaluation of Export Offers” in all correspondence related to this collection. Comments received generally will be posted without change to http://www.regulations.gov, including any personal and/or business confidential information provided. To confirm receipt of your comment(s), please check www.regulations.gov, approximately two to three days after submission to verify posting (except allow 30 days for posting of comments submitted by mail).

    FOR FURTHER INFORMATION CONTACT:

    Mr. Curtis E. Glover, Sr., Procurement Analyst, Office of Governmentwide Acquisition Policy, GSA, 202-501-4082 or via email at [email protected].

    SUPPLEMENTARY INFORMATION:

    A. Purpose

    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 collects information regarding the vendor's preference for delivery ports. The information is used to evaluate offers [on the basis of shipment through the port resulting in the lowest cost to the Government.

    B. Annual Reporting Burden

    Respondents: 100.

    Responses per Respondent: 4.

    Annual Responses: 400.

    Hours per Response: 0.25.

    Total Burden Hours: 100.

    C. Public Comments

    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.

    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 “9000-0057, Evaluation of Export Offers” in all correspondence.

    Dated: February 3, 2016. Lorin S. Curit, Director, Federal Acquisition Policy Division, Office of Governmentwide Acquisition Policy, Office of Acquisition Policy, Office of Governmentwide Policy.
    [FR Doc. 2016-02448 Filed 2-5-16; 8:45 am] BILLING CODE 6820-EP-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES Centers for Disease Control and Prevention [Docket No. CDC-2016-0015] Proposed Revised Vaccine Information Materials for Hepatitis A and Hepatitis B Vaccines AGENCY:

    Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).

    ACTION:

    Notice with comment period.

    SUMMARY:

    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.

    DATES:

    Written comments must be received on or before April 8, 2016.

    ADDRESSES:

    You may submit comments, identified by Docket No. CDC-2016-0015, by any of the following methods:

    Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.

    Mail: Written comments should be addressed to Suzanne Johnson-DeLeon, National Center for Immunization and Respiratory Diseases, Centers for Disease Control and Prevention, Mailstop A-19, 1600 Clifton Road NE., Atlanta, Georgia 30329.

    Instructions: All submissions received must include the agency name and docket number. All relevant comments received will be posted without change to http://regulations.gov, including any personal information provided. For access to the docket to read background documents or comments received, go to http://www.regulations.gov.

    FOR FURTHER INFORMATION CONTACT:

    Skip Wolfe ([email protected]), National Center for Immunization and Respiratory Diseases, Centers for Disease Control and Prevention, Mailstop A-19, 1600 Clifton Road NE., Atlanta, Georgia 30329.

    SUPPLEMENTARY INFORMATION:

    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, Haemophilus influenzae type b (Hib), varicella (chickenpox), pneumococcal conjugate, rotavirus, hepatitis A, meningococcal, human papillomavirus (HPV), and seasonal influenza vaccines. Instructions for use of the vaccine information materials are found on the CDC Web site at: http://www.cdc.gov/vaccines/hcp/vis/index.html.

    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 http://www.regulations.gov (see Docket Number CDC-2016-0015). Comments submitted will be considered in finalizing these materials. When the final materials are published in the Federal Register, the notice will include an effective date for their mandatory use.

    Sandra Cashman, Executive Secretary, Centers for Disease Control and Prevention.
    [FR Doc. 2016-02395 Filed 2-5-16; 8:45 am] BILLING CODE 4163-18-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES Administration for Children and Families Submission for OMB Review; Comment Request

    Title: Same-sex relationships: Updates to Healthy Marriage and Relationship Education.

    OMB No.: New Collection.

    Description: The Administration for Children and Families (ACF) will examine how healthy marriage programs currently approach, and could approach, serving sexual minority populations, that is, lesbian, gay, and bisexual populations. ACF expects to collect and analyze data from a range of information collection efforts—including interviews with program administrators, program managers, healthy marriage and relationship programming experts, and focus groups with program applicants and program attendees—to propose methods and practices for serving such couples/individuals/youth.

    Respondents: Current program applicants and participants, program managers and facilitators, and experts in the field.

    Annual Burden Estimates Instrument
  • (and appendix No.)
  • Total/
  • annual
  • number of
  • respondents
  • Number of
  • responses per respondent
  • Average
  • burden hours per response
  • Annual burden hours
    Focus Group Guide for Adult Applicants (Instrument #1) 18 1 1.5 27 Focus Group Guide for Adult Attendees (Instrument #2) 36 1 1.5 54 Focus Group Guide for Youth (Instrument #3) 36 1 1.5 54 Interview Guide with Experts (Instrument #4) 12 1 1 12 Interview Guide with Program Managers (Instrument #5) 10 1 1 10 Interview Guide with Facilitators (Instrument #6) 10 1 1 10 Staff Recruitment Script 90 1 .25 23

    Estimated Annual Burden Hours: 190.

    Additional Information: Copies of the proposed collection may be obtained by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 330 C Street SW., Washington, DC 20201, Attn: OPRE Reports Clearance Officer. All requests should be identified by the title of the information collection. Email address: [email protected].

    OMB Comment: OMB is required to make a decision concerning the collection of information between 30 and 60 days after publication of this document in the Federal Register. Therefore, a comment is best assured of having its full effect if OMB receives it within 30 days of publication. Written comments and recommendations for the proposed information collection should be sent directly to the following: Office of Management and Budget, Paperwork Reduction Project, Email: [email protected], Attn: Desk Officer for the Administration for Children and Families.

    Robert Sargis, ACF Certifying Officer.
    [FR Doc. 2016-02358 Filed 2-5-16; 8:45 am] BILLING CODE 4184-73-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES Administration for Children and Families Submission for OMB Review; Comment Request

    Title: National Center on Early Head Start-Child Care Partnerships (NCEHS-CCP) Evaluation.

    OMB No.: New Collection.

    Description: The Administration for Children and Families (ACF) in the Department of Health and Human Services (HHS) has awarded 275 Early Head Start expansion and Early Head Start-child care partnership grants (EHS-CCP) in 50 states; Washington, DC; Puerto Rico; and the Northern Mariana Islands. These grants will allow new or existing Early Head Start programs to partner with local child care centers and family child care providers to expand high-quality early learning opportunities for infants and toddlers from low-income families.

    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:

    Stakeholder survey. Web-based surveys will be conducted in the spring of 2016 and 2018 with key stakeholders (including regional T/TA specialists, CCDF administrators, Head Start state and national collaboration office directors, and implementation planners and fiscal consultants). The stakeholder survey will collect information about the types of support they received from NCEHS-CCP in the past year, their satisfaction with the support, how the T/TA informed their work with EHS-CCP grantees, and how support could be improved.

    Stakeholder telephone interviews. Semi-structured telephone interviews will be conducted in spring of 2017 and 2019 with a purposively selected group of stakeholders that complete the stakeholder survey. The interviews will explore in more detail the types of T/TA support participants received from NCEHS-CCP, how that support has informed their work with EHS-CCP grantees, their satisfaction with the support, successes and challenges, and suggestions for improvement.

    A 60-Day Federal Register Notice was published for this study on October 27, 2015. This 30-Day Federal Register Notice covers the following data collection activities: (1) Stakeholder survey, and (4) stakeholder telephone interviews.

    Respondents: Respondents include regional T/TA specialists, CCDF administrators, Head Start state and national collaboration office directors, and implementation planners and fiscal consultants.

    Annual Burden Estimates Instrument Number of
  • respondents
  • Annual
  • number of
  • responses per respondent
  • Number of
  • responses per respondent
  • Average
  • burden hours
  • per response
  • Total burden hours
    Stakeholder survey 350 1 2 0.5 175 Stakeholder telephone interviews 150 1 1 1.0 75

    Estimated Total Annual Burden Hours: 250.

    Additional Information: Copies of the proposed collection may be obtained by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 330 C Street SW., Washington, DC 20201. Attention Reports Clearance Officer. All requests should be identified by the title of the information collection. Email address: [email protected].

    OMB Comment: OMB is required to make a decision concerning the collection of information between 30 and 60 days after publication of this document in the Federal Register. Therefore, a comment is best assured of having its full effect if OMB receives it within 30 days of publication. Written comments and recommendations for the proposed information collection should be sent directly to the following: Office of Management and Budget, Paperwork Reduction Project, Email: [email protected], Attn: Desk Officer for the Administration for Children and Families.

    Robert Sargis, Reports Clearance Officer.
    [FR Doc. 2016-02351 Filed 2-5-16; 8:45 am] BILLING CODE 4184-01-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES Administration for Children and Families Proposed Information Collection Activity; Comment Request Proposed Projects

    Title: Procedures for Requests from Tribal Lead Agencies to use Child Care and Development Fund (CCDF) Funds for Construction or Major Renovation of Child Care Facilities.

    OMB No.: 0970-0160.

    Description: The Child Care and Development Block Grant Act, as amended, allows Indian Tribes to use Child Care and Development Fund (CCDF) grant awards for construction and renovation of child care facilities. A tribal grantee must first request and receive approval from the Administration for Children and Families (ACF) before using CCDF funds for construction or major renovation. This information collection contains the statutorily-mandated uniform procedures for the solicitation and consideration of requests, including instructions for preparation of environmental assessments in conjunction with the National Environmental Policy Act. The proposed draft procedures update the procedures that were originally issued in August 1997 and incorporate changes made by the Child Care and Development Block Grant Act of 2014, which now allows for a waiver to the requirement that the use of funds for construction or renovation does not result in the decrease in child care services. Respondents will be CCDF tribal grantees requesting to use CCDF funds for construction or major renovation.

    Respondents: Tribal Child Care Lead Agencies acting on behalf of Tribal Governments.

    Annual Burden Estimates Instrument Number of
  • respondents
  • Number of
  • responses per respondent
  • Average
  • burden
  • hours per
  • response
  • Total burden
  • hours
  • Construction or Major Renovation of Tribal Child Care Facilities 5 1 20 100

    Estimated Total Annual Burden Hours: 100.

    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: [email protected]. All requests should be identified by the title of the information collection.

    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.

    Robert Sargis, Reports Clearance Officer.
    [FR Doc. 2016-02297 Filed 2-5-16; 8:45 am] BILLING CODE 4184-01-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES Administration for Community Living Agency Information Collection Activities; Proposed Collection; Comment Request; Extension for a Currently Approved Collection, State Plan for Independent Living (SPIL) AGENCY:

    Independent Living Administration, Administration for Community Living, HHS.

    ACTION:

    Notice.

    SUMMARY:

    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 Federal Register concerning each proposed collection of information, including each proposed extension of an existing collection of information, and to allow public comment in response to the notice.

    DATES:

    Submit written comments on the collection of information by March 9, 2016.

    ADDRESSES:

    Submit written comments on the collection of information by email to [email protected], Attn: OMB Desk Officer for ACL.

    FOR FURTHER INFORMATION CONTACT:

    Veronica Hogan, Administration for Community Living, Washington, DC 20201. Telephone: (202) 795-7365; email: [email protected].

    SUPPLEMENTARY INFORMATION:

    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 Rehabilitation Act of 1973, as amended (Pub. L. 105-220). The SPIL encompasses the activities planned by the state to achieve its specified independent living objectives and reflects the state's commitment to comply with all applicable statutory and regulatory requirements during the three years covered by the plan. Part I of the SPIL is a series of assurances, or statements of compliance, based on legal and regulatory provisions governing the SILS and CIL programs. Part II of the SPIL consists of narrative sections in which the state describes its independent living objectives, services, activities and operational details.

    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 Federal Register concerning each proposed collection of information, including each proposed extension of an existing collection of information, before submitting the collection to OMB for approval. To comply with this requirement, ACL is publishing notice of the proposed collection of information set forth in this document. With respect to the following collection of information, ACL invites comments on: (1) Whether the proposed collection of information is necessary for the proper performance of ACL's functions, including whether the information will have practical utility; (2) the accuracy of ACL's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques when appropriate, and other forms of information technology.

    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.

    Dated: February 2, 2016. Kathy Greenlee, Administrator and Assistant Secretary for Aging.
    [FR Doc. 2016-02348 Filed 2-5-16; 8:45 am] BILLING CODE 4154-01-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES Food and Drug Administration Office of Foods and Veterinary Medicine; Center for Food Safety and Applied Nutrition; Statement of Organization, Functions, and Delegations of Authority AGENCY:

    Food and Drug Administration, HHS.

    ACTION:

    Notice.

    SUMMARY:

    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.

    FOR FURTHER INFORMATION CONTACT:

    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:

    DJJH ORGANIZATION. CFSAN is headed by the Center Director and includes the following organizational units:

    Center for Food Safety and Applied Nutrition (DJJH) Office of the Center Director (DJJHA) Office of Management (DJJHB) Office of Analytics and Outreach (DJJHC) Office of Food Safety (DJJHD) Office of Cosmetics and Colors (DJJHE) Office of Regulatory Science (DJJHF) Office of Food Additive Safety (DJJHG) Office of Compliance (DJJHH) Office of Applied Research and Safety Assessment (DJJHI) Office of Regulations, Policy and Social Sciences (DJJHJ) Office of Nutrition and Food Labeling (DJJHK) Office of Dietary Supplement Programs (DJJHL)

    DJJHK ORGANIZATION. ONFL is headed by the Office Director and includes the following organizational units:

    Office of Nutrition and Food Labeling (DJJHK) Food Labeling and Standards Staff Nutrition Programs Staff

    DJJHL ORGANIZATION. ODSP is headed by the Office Director and includes the following organizational units:

    Office of Dietary Supplement Programs (DJJHL) Evaluation and Research Staff Regulatory Implementation Staff

    II. Delegations of Authority. Pending further delegation, directives, or orders by the Commissioner of Food and Drugs, all delegations and re-delegations of authority made to officials and employees of affected organizational components will continue in them or their successors pending further re-delegations, provided they are consistent with this reorganization.

    III. Electronic Access. Persons interested in seeing the completed Staff Manual Guide can find it on FDA's Webs site at: http://www.fda.gov/AboutFDA/ReportsManualsForms/StaffManualGuides/default.htm.

    Authority: 44 U.S.C. 3101.) Dated: December 22, 2015. Sylvia M. Burwell, Secretary.
    [FR Doc. 2016-02444 Filed 2-5-16; 8:45 am] BILLING CODE 4160-01-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES National Institutes of Health National Institute on Deafness and Other Communication; Disorders Notice of Closed Meeting

    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.

    Name of Committee: Board of Scientific Counselors, NIDCD.

    Date: March 8, 2016.

    Time: 3:00 p.m. to 4:00 p.m.

    Agenda: To review and evaluate personal qualifications and performance, and competence of individual investigators.

    Place: National Institutes of Health, Building 31, Room 3C05, 31 Center Drive, Bethesda, MD 20892 (Telephone Conference Call).

    Contact Person: Andrew J. Griffith, Ph.D., MD, Director, Division of Intramural Research, National Institute on Deafness and Other Communication Disorders, 35A Convent Drive, GF 103 Rockville, MD 20892, 301-496-1960, [email protected].

    Information is also available on the Institute's/Center's home page: http://www.nidcd.nih.gov/about/groups/bsc/, where an agenda and any additional information for the meeting will be posted when available.

    (Catalogue of Federal Domestic Assistance Program Nos. 93.173, Biological Research Related to Deafness and Communicative Disorders, National Institutes of Health, HHS)
    Dated: February 2, 2016. Sylvia Neal, Program Analyst, Office of Federal Advisory Committee Policy.
    [FR Doc. 2016-02318 Filed 2-5-16; 8:45 am] BILLING CODE 4140-01-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES National Institutes of Health National Library of Medicine; Amended Notice of Meeting

    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 Federal Register on January 26, 2016 (81 FR 4319).

    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.

    Dated: February 2, 2016. Michelle Trout, Program Analyst, Office of Federal Advisory Committee Policy.
    [FR Doc. 2016-02315 Filed 2-5-16; 8:45 am] BILLING CODE 4140-01-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES National Institutes of Health National Institute of Diabetes and Digestive and Kidney Diseases; Notice of Closed Meetings

    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.

    Name of Committee: National Institute of Diabetes and Digestive and Kidney Diseases Special Emphasis Panel; Time-Sensitive Obesity.

    Date: March 18, 2016.

    Time: 1:00 p.m. to 2:30 p.m.

    Agenda: To review and evaluate grant applications.

    Place: National Institutes of Health, Two Democracy Plaza, 6707 Democracy Boulevard, Bethesda, MD 20892 (Telephone Conference Call).

    Contact Person: Michele L. Barnard, Ph.D., Scientific Review Officer, Review Branch, DEA, NIDDK, National Institutes of Health, Room 753, 6707 Democracy Boulevard, Bethesda, MD 20892-2542, (301) 594-8898, [email protected].

    Name of Committee: National Institute of Diabetes and Digestive and Kidney Diseases Special Emphasis Panel; PAR-13-305 Collaborative Interdisciplinary Team Science (R24): Pharmacological Action of Anti-Diabetes Drugs.

    Date: March 30, 2016.

    Time: 1:00 p.m. to 3:00 p.m.

    Agenda: To review and evaluate grant applications.

    Place: National Institutes of Health, Two Democracy Plaza, 6707 Democracy Boulevard, Bethesda, MD 20892 (Telephone Conference Call).

    Contact Person: Ann A. Jerkins, Ph.D., Scientific Review Officer, Review Branch, DEA, NIDDK, National Institutes of Health, Room 759, 6707 Democracy Boulevard, Bethesda, MD 20892-5452, 301-594-2242, [email protected].

    Name of Committee: National Institute of Diabetes and Digestive and Kidney Diseases Special Emphasis Panel; K12 UroEpi.

    Date: March 30, 2016.

    Time: 12:00 p.m. to 3:00 p.m.

    Agenda: To review and evaluate grant applications.

    Place: National Institutes of Health, Two Democracy Plaza, 6707 Democracy Boulevard, Bethesda, MD 20892 (Telephone Conference Call).

    Contact Person: Barbara A. Woynarowska, Ph.D., Scientific Review Officer, Review Branch, DEA, NIDDK, National Institutes of Health, Room 754, 6707 Democracy Boulevard, Bethesda, MD 20892-5452, (301) 402-7172, [email protected].

    (Catalogue of Federal Domestic Assistance Program Nos. 93.847, Diabetes, Endocrinology and Metabolic Research; 93.848, Digestive Diseases and Nutrition Research; 93.849, Kidney Diseases, Urology and Hematology Research, National Institutes of Health, HHS)
    Dated: February 2, 2016. David Clary, Program Analyst, Office of Federal Advisory Committee Policy.
    [FR Doc. 2016-02317 Filed 2-5-16; 8:45 am] BILLING CODE 4140-01-P
    DEPARTMENT OF HEALTH AND HUMAN SERVICES National Institutes of Health National Heart, Lung, And Blood Institute; Notice of Closed Meeting

    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.

    Name of Committee: National Heart, Lung, and Blood Institute Special Emphasis Panel; Grant Review for NHLBI K Award Recipients.

    Date: March 1, 2016.

    Time: 8:00 a.m. to 5:00 p.m.

    Agenda: To review and evaluate grant applications.

    Place: Bethesda Marriott Suites, 6711 Democracy Boulevard, Bethesda, MD 20817.

    Contact Person: Melissa E Nagelin, Ph.D., Scientific Review Officer, Office of Scientific Review/DERA National Heart, Lung, and Blood Institute 6701 Rockledge Drive, Room 7202, Bethesda, MD 20892, 301-435-0297, [email protected].

    (Catalogue of Federal Domestic Assistance Program Nos. 93.233, National Center for Sleep Disorders Research; 93.837, Heart and Vascular Diseases Research; 93.838, Lung Diseases Research; 93.839, Blood Diseases and Resources Research, National Institutes of Health, HHS)
    Dated: February 2, 2016. Michelle Trout, Program Analyst, Office of Federal Advisory Committee Policy.
    [FR Doc. 2016-02316 Filed 2-5-16; 8:45 am] BILLING CODE 4140-01-P
    DEPARTMENT OF HOMELAND SECURITY U.S. Customs and Border Protection [1651-0004] Agency Information Collection Activities: Application for Exportation of Articles Under Special Bond AGENCY:

    U.S. Customs and Border Protection, Department of Homeland Security.

    ACTION:

    30-Day notice and request for comments; Extension of an existing collection of information.

    SUMMARY:

    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 published to obtain comments from the public and affected agencies.

    DATES:

    Written comments should be received on or before March 9, 2016 to be assured of consideration.

    ADDRESSES:

    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 [email protected] or faxed to (202) 395-5806.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    This proposed information collection was previously published in the Federal Register (80 FR 62085) on October 15, 2015, allowing for a 60-day comment period. This notice allows for an additional 30 days for public comments. This process is conducted in accordance with 5 CFR 1320.10. CBP invites the general public and other Federal agencies to comment on proposed and/or continuing information collections pursuant to the Paperwork Reduction Act of 1995 (Pub. L. 104-13; 44 U.S.C. 3507). The comments should address: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimates 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, including the use of automated collection techniques or the use of other forms of information technology; and (e) the annual costs to respondents or record keepers from the collection of information (total capital/startup costs and operations and maintenance costs). The comments that are submitted will be summarized and included in the CBP request for OMB approval. All comments will become a matter of public record. In this document, CBP is soliciting comments concerning the following information collection:

    Title: Application for Exportation of Articles under Special Bond.

    OMB Number: 1651-0004.

    Form Number: CBP Form 3495.

    Abstract: CBP Form 3495, Application for Exportation of Articles Under Special Bond, is an application for exportation of articles entered under temporary bond pursuant to 19 U.S.C. 1202, Chapter 98, subchapter XIII, Harmonized Tariff Schedule of the United States, and 19 CFR 10.38. CBP Form 3495 is used by importers to notify CBP that the importer intends to export goods that were subject to a duty exemption based on a temporary stay in this country. It also serves as a permit to export in order to satisfy the importer's obligation to export the same goods and thereby get a duty exemption. This form is accessible at: http://www.cbp.gov/newsroom/publications/forms?title=3495&=Apply.

    Current Actions: CBP proposes to extend the expiration date of this information collection with no change to the burden hours or to the information being collected.

    Type of Review: Extension (without change).

    Affected Public: Businesses.

    Estimated Number of Respondents: 500.

    Estimated Number of Responses per Respondent: 30.

    Estimated Total Annual Responses: 15,000.

    Estimated Time per Response: 8 minutes.

    Estimated Total Annual Burden Hours: 2,000.

    Dated: February 1, 2016. Tracey Denning, Agency Clearance Officer, U.S. Customs and Border Protection.
    [FR Doc. 2016-02398 Filed 2-5-16; 8:45 am] BILLING CODE 9111-14-P
    DEPARTMENT OF HOMELAND SECURITY U.S. Customs and Border Protection Quarterly IRS Interest Rates Used in Calculating Interest on Overdue Accounts and Refunds on Customs Duties AGENCY:

    U.S. Customs and Border Protection, Department of Homeland Security.

    ACTION:

    General notice.

    SUMMARY:

    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.

    DATES:

    Effective Date: January 1, 2016.

    FOR FURTHER INFORMATION CONTACT:

    Michael P. Dean, Revenue Division, Collection and Refunds Branch, 6650 Telecom Drive, Suite #100, Indianapolis, Indiana 46278; telephone (317) 614-4882.

    SUPPLEMENTARY INFORMATION:

    Background

    Pursuant to 19 U.S.C. 1505 and Treasury Decision 85-93, published in the Federal Register on May 29, 1985 (50 FR 21832), the interest rate paid on applicable overpayments or underpayments of customs duties must be in accordance with the Internal Revenue Code rate established under 26 U.S.C. 6621 and 6622. Section 6621 provides different interest rates applicable to overpayments: One for corporations and one for non-corporations.

    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 accounts and refunds of customs duties, is published in summary format.

    Beginning date Ending
  • date
  • Under-payments
  • (percent)
  • Over-payments
  • (percent)
  • Corporate overpayments
  • (Eff. 1-1-99)
  • (percent)
  • 070174 063075 6 6 070175 013176 9 9 020176 013178 7 7 020178 013180 6 6 020180 013182 12 12 020182 123182 20 20 010183 063083 16 16 070183 123184 11 11 010185 063085 13 13 070185 123185 11 11 010186 063086 10 10 070186 123186 9 9 010187 093087 9 8 100187 123187 10 9 010188 033188 11 10 040188 093088 10 9 100188 033189 11 10 040189 093089 12 11 100189 033191 11 10 040191 123191 10 9 010192 033192 9 8 040192 093092 8 7 100192 063094 7 6 070194 093094 8 7 100194 033195 9 8 040195 063095 10 9 070195 033196 9 8 040196 063096 8 7 070196 033198 9 8 040198 123198 8 7 010199 033199 7 7 6 040199 033100 8 8 7 040100 033101 9 9 8 040101 063001 8 8 7 070101 123101 7 7 6 010102 123102 6 6 5 010103 093003 5 5 4 100103 033104 4 4 3 040104 063004 5 5 4 070104 093004 4 4 3 100104 033105 5 5 4 040105 093005 6 6 5 100105 063006 7 7 6 070106 123107 8 8 7 010108 033108 7 7 6 040108 063008 6 6 5 070108 093008 5 5 4 100108 123108 6 6 5 010109 033109 5 5 4 040109 123110 4 4 3 010111 033111 3 3 2 040111 093011 4 4 3 100111 033116 3 3 2
    Dated: February 3, 2016. R. Gil Kerlikowske, Commissioner.
    [FR Doc. 2016-02402 Filed 2-5-16; 8:45 am] BILLING CODE 9111-14-P
    DEPARTMENT OF HOMELAND SECURITY U.S. Customs and Border Protection [1651-0057] Agency Information Collection Activities: Country of Origin Marking Requirements for Containers or Holders AGENCY:

    U.S. Customs and Border Protection, Department of Homeland Security.

    ACTION:

    30-Day notice and request for comments; Extension of an existing collection of information.

    SUMMARY:

    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.

    DATES:

    Written comments should be received on or before March 9, 2016 to be assured of consideration.

    ADDRESSES:

    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 [email protected] or faxed to (202) 395-5806.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    This proposed information collection was previously published in the Federal Register (80 FR 60396) on October 6, 2015, allowing for a 60-day comment period. This notice allows for an additional 30 days for public comments. This process is conducted in accordance with 5 CFR 1320.10. CBP invites the general public and other Federal agencies to comment on proposed and/or continuing information collections pursuant to the Paperwork Reduction Act of 1995 (Pub. L. 104-13; 44 U.S.C. 3507). The comments should address: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimates 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, including the use of automated collection techniques or the use of other forms of information technology; and (e) the annual costs to respondents or record keepers from the collection of information (total capital/startup costs and operations and maintenance costs). The comments that are submitted will be summarized and included in the CBP request for OMB approval. All comments will become a matter of public record. In this document, CBP is soliciting comments concerning the following information collection:

    Title: Country of Origin Marking Requirements for Containers or Holders.

    OMB Number: 1651-0057.

    Abstract: Section 304 of the Tariff Act of 1930, as amended, 19 U.S.C. 1304, requires each imported article of foreign origin, or its container, to be marked in a conspicuous place as legibly, indelibly and permanently as the nature of the article or container permits, with the English name of the country of origin. The marking informs the ultimate purchaser in the United States of the name country in which the article was manufactured or produced. The marking requirements for containers are provided for by 19 CFR 134.22(b).

    Current Actions: CBP proposes to extend the expiration date of this information collection with no change to the burden hours or to the information collected.

    Type of Review: Extension (without change).

    Affected Public: Businesses.

    Estimated Number of Respondents: 250.

    Estimated Number of Responses per Respondent: 40.

    Estimated Time per Response: 15 seconds.

    Estimated Total Annual Burden Hours: 41.

    Dated: February 3, 2016. Tracey Denning, Agency Clearance Officer, U.S. Customs and Border Protection.
    [FR Doc. 2016-02401 Filed 2-5-16; 8:45 am] BILLING CODE 9111-14-P
    DEPARTMENT OF HOMELAND SECURITY U.S. Customs and Border Protection Approval of SGS North America, Inc., as a Commercial Gauger AGENCY:

    U.S. Customs and Border Protection, Department of Homeland Security.

    ACTION:

    Notice of approval of SGS North America, Inc., as a commercial gauger.

    SUMMARY:

    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.

    DATES:

    Effective dates: The approval of SGS North America, Inc., as a commercial gauger became effective on April 29, 2015. The next triennial inspection date will be scheduled for April 2018.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    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):

    API
  • chapters
  • Title
    3 Tank gauging. 7 Temperature Determination. 8 Sampling. 12 Calculations. 17 Maritime Measurements.

    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 [email protected]. Please reference the following Web site for the current CBP Approved Gaugers and Accredited Laboratories List.

    http://www.cbp.gov/about/labs-scientific/commercial-gaugers-and-laboratories Dated: January 29, 2016. Ira S. Reese, Executive Director, Laboratories and Scientific Services Directorate.
    [FR Doc. 2016-02400 Filed 2-5-16; 8:45 am] BILLING CODE 9111-14-P
    DEPARTMENT OF HOMELAND SECURITY U.S. Customs and Border Protection Approval of SGS North America, Inc., as a Commercial Gauger AGENCY:

    U.S. Customs and Border Protection, Department of Homeland Security.

    ACTION:

    Notice of approval of SGS North America, Inc., as a commercial gauger.

    SUMMARY:

    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.

    DATES:

    Effective Dates: The approval of SGS North America, Inc., as a commercial gauger became effective on August 2015. The next triennial inspection date will be scheduled for August 2018.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    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):

    API
  • chapters
  • Title
    3 Tank gauging. 7 Temperature Determination. 8 Sampling. 12 Calculations. 17 Maritime Measurements.

    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 [email protected]. Please reference the following Web site for the current CBP Approved Gaugers and Accredited Laboratories List.

    http://www.cbp.gov/about/labs-scientific/commercial-gaugers-and-laboratories Dated: January 29, 2016. Ira S. Reese, Executive Director, Laboratories and Scientific Services Directorate.
    [FR Doc. 2016-02399 Filed 2-5-16; 8:45 am] BILLING CODE 9111-14-P
    DEPARTMENT OF HOMELAND SECURITY [Docket No. DHS-2012-0022] Technical Resource for Incident Prevention (TRIPwire) User Registration AGENCY:

    National Protection and Programs Directorate, DHS.

    ACTION:

    30-day notice and request for comments; Extension of previously approved collection: 1670-0028.

    SUMMARY:

    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 Federal Register on September 4, 2015, for a 60-day public comment period. DHS received no comments. The purpose of this notice is to allow an additional 30 days for public comments.

    DATES:

    Comments are encouraged and will be accepted until March 9, 2016. This process is conducted in accordance with 5 CFR 1320.10.

    ADDRESSES:

    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:

    Federal eRulemaking Portal: http://www.regulations.gov.

    Email: [email protected]. Include the docket number in the subject line of the message.

    Fax: (202) 395-5806.

    Instructions: All submissions received must include the words “Department of Homeland Security” and the docket number for this action. Comments received will be posted without alteration at http://www.regulations.gov, including any personal information provided.

    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, e.g., permitting electronic submissions of responses.

    FOR FURTHER INFORMATION CONTACT:

    Dennis Malloy, DHS/NPPD/IP/PSCD/OBP, [email protected].

    SUPPLEMENTARY INFORMATION:

    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 design and emplacement considerations. TRIPwire was established as an IED information-sharing resource under Homeland Security Presidential Directive 19 (HSPD-19), which calls for a unified national policy for the prevention and detection of, protection against, and response to terrorist use of explosives in the United States. Users from Federal, State, local, and tribal government entities; as well as business and for-profit industries can register through the TRIPwire Secure Portal. The TRIPwire portal contains sensitive information related to terrorist use of explosives, and, therefore, user information is needed to verify eligibility and access to the system. TRIPwire applicants must provide their full name, assignment, citizenship, job title, employer name, professional address and contact information, as well as an Employment Verification Contact and their contact information. The system does not store sensitive personally identifiable information (PII) such as social security numbers. The collection of PII by TRIPwire to establish user accounts occurs in accordance with the DHS Privacy Impact Assessment PIA-015, “DHS Web Portals,” DHS/ALL-004—General Information Technology Access Account Records System (GITAARS) November 27, 2012, 77 FR 70792, and DHS/ALL-002—Department of Homeland Security Mailing and Other Lists System November 25, 2008, 73 FR 71659. Participation in TRIPwire is voluntary. However, those who choose to participate are required to complete the registration process to obtain access. This requirement is designed to measure users' suitability to access the secure environment.

    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.

    Analysis

    Agency: Department of Homeland Security, National Protection and Programs Directorate, Office of Infrastructure Protection, Protective Security Coordination Division, Office for Bombing Prevention.

    Title: Technical Resource for Incident Prevention (TRIPwire) User Registration.

    OMB Number: 1670-0028.

    Frequency: Once.

    Affected Public: Federal, State, local, and tribal government entities, business, and for-profit.

    Number of Respondents: 3,500 respondents (estimate).

    Estimated Time per Respondent: 10 minutes.

    Total Burden Hours: 595 annual burden hours.

    Total Burden Cost (capital/startup): $0.

    Total Recordkeeping Burden: $0 (This assessment resides on the TRIPwire Portal, and there is no cost associated with the recordkeeping of TRIPwire-related information.)

    Total Burden Cost (operating/maintaining): $16,006.

    Dated: February 1, 2016. David Epperson, Chief Information Officer, National Protection and Programs Directorate, Department of Homeland Security.
    [FR Doc. 2016-02354 Filed 2-5-16; 8:45 am] BILLING CODE 9110-9P-P
    DEPARTMENT OF HOMELAND SECURITY [Docket No. DHS-2014-0010] Infrastructure Assessments and Training AGENCY:

    National Protection and Programs Directorate, DHS.

    ACTION:

    30-day notice and request for comments; Reinstatement, with change, of a previously approved collection: 1670-0009.

    SUMMARY:

    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).

    DATES:

    Comments are encouraged and will be accepted until March 9, 2016. This process is conducted in accordance with 5 CFR 1320.10.

    ADDRESSES:

    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, [email protected]. Written comments should reach the contact person listed no later than March 9, 2016. Comments must be identified by “DHS-2014-0010”and may be submitted by one of the following methods:

    Federal eRulemaking Portal: http://www.regulations.gov.

    Email: Include the docket number in the subject line of the message.

    Instructions: All submissions received must include the words “Department of Homeland Security” and the docket number for this action. Comments received will be posted without alteration at http://www.regulations.gov, including any personal information provided.

    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, e.g., permitting electronic submissions of responses.

    FOR FURTHER INFORMATION CONTACT:

    Kimberly Sass, DHS/NPPD/IP/IICD, [email protected].

    SUPPLEMENTARY INFORMATION:

    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 sponsor information, and additional questions related to the user's role in using the information. Upon registering for Chemical Security Awareness Training, a collection form requests the trainee's desired username, password, proposed secret question & response, and company type, size, name, & location. For the voluntary User Satisfaction Survey, the collection form requests information regarding the user's job duties, types of information sought via the IP Gateway, access patterns, and system usability ratings. The survey information will be used to evaluate program and training performance as well as to gather any additional requirements for future IP Gateway system updates.

    Analysis

    Agency: Department of Homeland Security, National Protection and Programs Directorate, Office of Infrastructure Protection, Infrastructure Information Collection Division.

    Title: Infrastructure Assessments and Training.

    OMB Number: 1670-0009.

    Frequency: Annually, quarterly, monthly, and weekly.

    Affected Public: Chief Information Officers, Chief Information Security Officers, Chief Technology Officers, and Federal and State, local, tribal and territorial communities involved in the protection of CI.

    Number of Respondents: 9000 respondents (estimate).

    Estimated Time per Respondent: .5 hours (estimate).

    Total Burden Hours: 4,500 annual burden hours (estimate).

    Total Burden Cost (capital/startup): $0.

    Total Recordkeeping Burden: $0.

    Total Burden Cost (operating/maintaining): $106,515.50 (estimate).

    Dated: February 1, 2016. David Epperson, Chief Information Officer, National Protection and Programs Directorate, Department of Homeland Security.
    [FR Doc. 2016-02355 Filed 2-5-16; 8:45 am] BILLING CODE 9110-9P-P
    DEPARTMENT OF HOMELAND SECURITY [Docket No. DHS-2015-0028] Gratuitous Services Agreement and Volunteer Release and Hold Harmless AGENCY:

    National Protection and Programs Directorate, DHS.

    ACTION:

    30-Day notice and request for comments; New Information Collection Request: 1670—NEW.

    SUMMARY:

    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 Federal Register on August 20, 2015 (80 FR 50649), for a 60-day public comment period. DHS received no comments. The purpose of this notice is to allow an additional 30 days for public comments.

    DATES:

    Comments are encouraged and will be accepted until March 9, 2016. This process is conducted in accordance with 5 CFR 1320.10.

    ADDRESSES:

    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 [email protected]. Comments must be identified by DHS-2015-0028 and may be submitted by one of the following methods:

    Federal eRulemaking Portal: http://www.regulations.gov.

    Email: [email protected]. Include the docket number in the subject line of the message.

    Fax: (202) 395-5806.

    Instructions: All submissions received must include the words “Department of Homeland Security” and the docket number for this action. Comments received will be posted without alteration at http://www.regulations.gov, including any personal information provided.

    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, e.g., permitting electronic submissions of responses.

    FOR FURTHER INFORMATION CONTACT:

    DHS/NPPD/IP/PSCD/OBP, 245 Murray Lane SW., Mail Stop 0612, Washington, DC 20528-0612 or [email protected].

    SUPPLEMENTARY INFORMATION:

    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.

    Analysis

    Agency: Department of Homeland Security, National Protection and Programs Directorate, Office of Infrastructure Protection, Protective Security Coordination Division, Office for Bombing Prevention.

    Title: Gratuitous Services Agreement and Volunteer Release and Hold Harmless form.

    OMB Number: 1670-NEW.

    Frequency: Varies.

    Affected Public: Participants in OBP training to include, but not limited to, emergency response personnel, firefighters, police officers, emergency medical teams, and emergency management personnel.

    Number of Respondents: 750 respondents (estimate).

    Estimated Time per Respondent: .2 hours.

    Total Burden Hours: 150 annual burden hours.

    Total Burden Cost (capital/startup): $0.

    Total Recordkeeping Burden: $0.

    Total Burden Cost (operating/maintaining): $6,831.00.

    Dated: February 1, 2016. David Epperson, Chief Information Officer, National Protection and Programs Directorate, Department of Homeland Security.
    [FR Doc. 2016-02356 Filed 2-5-16; 8:45 am] BILLING CODE 9110-9P-P
    DEPARTMENT OF HOMELAND SECURITY Transportation Security Administration [Docket No. TSA-2009-0018] Extension of Agency Information Collection Activity Under OMB Review: Certified Cargo Screening Program AGENCY:

    Transportation Security Administration, DHS.

    ACTION:

    30-Day notice.

    SUMMARY:

    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 Federal Register notice, with a 60-day comment period soliciting comments, of the following collection of information on November 30, 2015, 80 FR 74786. The collection involves: (1) Applications from entities that wish to become Certified Cargo Screening Facilities (CCSFs); (2) personally identifiable information to allow TSA to conduct security threat assessments on certain individuals employed by the CCSFs; (3) standard security programs or submission of a proposed modified security program or amendment to a security program; and (4) recordkeeping requirements for CCSFs. TSA is seeking the renewal of the ICR for the continuation of the Certified Cargo Screening Program in order to secure passenger aircraft carrying cargo.

    DATES:

    Send your comments by March 9, 2016. A comment to OMB is most effective if OMB receives it within 30 days of publication.

    ADDRESSES:

    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 [email protected] or faxed to (202) 395-6974.

    FOR FURTHER INFORMATION CONTACT:

    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 [email protected].

    SUPPLEMENTARY INFORMATION:

    Comments Invited

    In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.), 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 OMB control number. The ICR documentation is available at http://www.reginfo.gov. Therefore, in preparation for OMB review and approval of the following information collection, TSA is soliciting comments to—

    (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.

    Information Collection Requirement

    Title: Certified Cargo Screening Program.

    Type of Request: Renewal of one currently approved ICR.

    OMB Control Number: 1652-0053.

    Forms(s): The forms used for this collection of information include CCSF Facility Profile Application (TSA Form 419B), CCSF Principal Attestation (TSA Form 419D), Security Profile (TSA Form 419E), and the Security Threat Assessment Application (TSA Form 419F).

    Affected Public: The collections of information that make up this ICR involve entities other than aircraft operators and include facilities upstream in the air cargo supply chain, such as shippers, manufacturers, warehousing entities, distributors, third party logistics companies, and indirect air carriers located in the United States.

    Abstract: TSA is seeking continued approval from OMB for the collection of information contained in the ICR. Companies seeking to become CCSFs are required to submit an application to TSA at least 90 calendar days before the intended date of operation, to include quantity, make, and model of the technology(ies) used to screen cargo. Prior to certification, the CCSF must also submit to an assessment of its facility by TSA. Once certified, the CCSF must operate in accordance with a TSA-approved security program. CCSFs must also collect personal information and submit such information to TSA so that TSA may conduct security threat assessments for individuals with unescorted access to cargo, and who have responsibility for screening cargo under title 49 Code of Federal Regulations (49 CFR) parts 1544, 1546, 1548, and 1549. CCSFs must also maintain screening, training, and other security-related records of compliance.

    Estimated Number of Respondents: 18,290.

    Estimated Annual Burden Hours: 7125.24 hours annually.

    Dated: February 2, 2016. Christina A. Walsh, Paperwork Reduction Act Officer, Office of Information Technology.
    [FR Doc. 2016-02341 Filed 2-5-16; 8:45 am] BILLING CODE 9110-05-P
    DEPARTMENT OF HOMELAND SECURITY U.S. Citizenship and Immigration Services [OMB Control Number 1615-0126] Agency Information Collection Activities: Collection of Qualitative Feedback Through Focus Groups; Extension, Without Change, of a Currently Approved Collection AGENCY:

    U.S. Citizenship and Immigration Services, Department of Homeland Security.

    ACTION:

    30-Day notice.

    SUMMARY:

    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 Federal Register on November 17, 2015, at 80 FR 71817, allowing for a 60-day public comment period. USCIS did receive one comment in connection with the 60-day notice.

    DATES:

    The purpose of this notice is to allow an additional 30 days for public comments. Comments are encouraged and will be accepted until March 9, 2016. This process is conducted in accordance with 5 CFR 1320.10.

    ADDRESSES:

    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 [email protected]. Comments may also be submitted via fax at (202) 395-5806 (This is not a toll-free number). All submissions received must include the agency name and the OMB Control Number 1615-0126.

    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 http://www.regulations.gov.

    FOR FURTHER INFORMATION CONTACT:

    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 http://www.uscis.gov, or call the USCIS National Customer Service Center at (800) 375-5283; TTY (800) 767-1833.

    SUPPLEMENTARY INFORMATION: Comments

    You may access the information collection instrument with instructions, or additional information by visiting the Federal eRulemaking Portal site at: http://www.regulations.gov and enter USCIS-2012-0004 in the search box. Written comments and suggestions from the public and affected agencies should address one or more of the following four points:

    (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, e.g., permitting electronic submission of responses.

    Overview of This Information Collection

    (1) Type of Information Collection Request: Extension, Without Change, of a Currently Approved Collection.

    (2) Title of the Form/Collection: Collection of Qualitative Feedback through Focus Groups.

    (3) Agency form number, if any, and the applicable component of the DHS sponsoring the collection: No Agency Form Number; U.S. Citizenship and Immigration Services (USCIS).

    (4) Affected public who will be asked or required to respond, as well as a brief abstract: Primary: Individuals or households; Business or other for-profit. The information collection activity will garner qualitative customer and stakeholder feedback in an efficient, timely manner, in accordance with the Administration's commitment to improving service delivery. By qualitative feedback USCIS means information that provides useful insights on perceptions and opinions, but not responses to statistical surveys that yield quantitative results that can be generalized to the population of study. This feedback will provide information on customer and stakeholder perceptions, experiences and expectations, provide an early warning of issues with service, and/or focus attention on areas where communication, training, or changes in operations might improve delivery of products or services. These collections will allow for ongoing, collaborative and actionable communications between the Agency and its customers and stakeholders and contribute directly to the improvement of program management. Feedback collected under this generic clearance will provide useful information, but it will not be generalized to the overall population. This data collection will not be used to generate quantitative information that is designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance.

    (5) An estimate of the total number of respondents and the amount of time estimated for an average respondent to respond: 3000 respondents × 1.5 hours per response.

    (6) An estimate of the total public burden (in hours) associated with the collection: The total estimated annual hour burden associated with this collection is 4,500 hours.

    (7) An estimate of the total public burden (in cost) associated with the collection: The estimated total annual cost burden associated with this collection of information is $0.

    Dated: February 3, 2016. Samantha Deshommes, Acting Chief, Regulatory Coordination Division, Office of Policy and Strategy, U.S. Citizenship and Immigration Services, Department of Homeland Security.
    [FR Doc. 2016-02409 Filed 2-5-16; 8:45 am] BILLING CODE 9111-97-P
    DEPARTMENT OF HOUSING AND URBAN DEVELOPMENT [Docket No. FR-5913-N-04] 60-Day Notice of Proposed Information Collection: Eligibility of a Nonprofit Corporation/Housing Consultant Certification AGENCY:

    Office of the Assistant Secretary for Housing—Federal Housing Commissioner, HUD.

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    Comments Due Date: April 8, 2016.

    ADDRESSES:

    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 [email protected] for a copy of the proposed forms or other available information. Persons with hearing or speech impairments may access this number through TTY by calling the toll-free Federal Relay Service at (800) 877-8339.

    FOR FURTHER INFORMATION CONTACT:

    Theodore F. Toon, Director Multifamily Housing Development, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410, email [email protected] or telephone 202-402-1142. This is not a toll-free number. Persons with hearing or speech impairments may access this number through TTY by calling the toll-free Federal Relay Service at (800) 877-8339.

    Copies of available documents submitted to OMB may be obtained from Ms. Pollard.

    SUPPLEMENTARY INFORMATION:

    This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.

    A. Overview of Information Collection

    Title of Information Collection: Eligibility of a Nonprofit Corporation/Housing Consultant Certification.

    OMB Approval Number: 2502-0057.

    Type of Request: Extension of currently approved collection.

    Form Number: HUD-3433, HUD-3434, HUD-3435, HUD-92531.

    Description of the need for the information and proposed use: The information collected on the “Eligibility of a Nonprofit Corpoeration/Houisng Consultant Certification” document provides HUD with vital information to determine whether the sponsor has qualifications necessary for successful sponsorship of housing projects. HUD-3433 provides a description of the relationship between the nonproftit and profit motivated entities involve in the transaction. HUD-3434 provides a determination of eligibility or ineligibility of the nonprofits before initial endorsement. Form HUD-92531 assure the consultant certifies that no payment has been or will be received either in the form of stock, options to buy stock or compensatory professional or financial services from any parties to the transaction.

    Respondents: Nonprofit sponsors or Nonprofit mortgagors.

    Estimated Number of Respondents: 70.

    Estimated Number of Responses: 80.

    Frequency of Response: 1.

    Average Hours per Response: 2.

    Total Estimated Burdens: 36.

    B. Solicitation of Public Comment

    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, e.g., permitting electronic submission of responses.

    HUD encourages interested parties to submit comment in response to these questions.

    Authority:

    Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35.

    Dated: February 2, 2016. Janet M. Golrick, Associate General Deputy Assistant Secretary for Housing—Associate Deputy Federal Housing Commissioner.
    [FR Doc. 2016-02389 Filed 2-5-16; 8:45 am] BILLING CODE 4210-67-P
    DEPARTMENT OF HOUSING AND URBAN DEVELOPMENT [Docket No. FR-5885-N-04] Final Fair Market Rents for the Housing Choice Voucher Program and Moderate Rehabilitation Single Room Occupancy Program Fiscal Year 2016; Revised AGENCY:

    Office of the Assistant Secretary for Policy Development and Research, HUD.

    ACTION:

    Notice of Final Fiscal Year (FY) 2016 Fair Market Rents (FMRs), Update.

    SUMMARY:

    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.

    DATES:

    Effective Date: The FMRs published in this notice are effective on February 8, 2016.

    FOR FURTHER INFORMATION CONTACT:

    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: http://www.huduser.gov/portal/datasets/fmr.html. FMRs are listed at the 40th or 50th percentile in Schedule B. For informational purposes, 40th percentile recent-mover rents for the areas with 50th percentile FMRs will be provided in the HUD FY 2016 FMR documentation system at http://www.huduser.gov/portal/datasets/fmr/fmrs/docsys.html?data=fmr16 and 50th percentile rents for all FMR areas are published http://www.huduser.gov/portal/datasets/50per.html.

    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.)

    SUPPLEMENTARY INFORMATION:

    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 Federal Register (80 FR 77124) (available from HUD at: http://www.huduser.gov/portal/datasets/fmr.html.

    The FMRs for the affected area are revised as follows:

    2016 Fair Market Rent Area FMR by number of bedrooms in unit 0 BR 1 BR 2 BR 3 BR 4 BR Oakland-Fremont, CA HUD Metro FMR Area 1380 1663 2103 2932 3268 Dated: January 26, 2016. Katherine M. O'Regan, Assistant Secretary for Policy Development & Research.
    [FR Doc. 2016-02383 Filed 2-5-16; 8:45 am] BILLING CODE 4210-67-P
    DEPARTMENT OF HOUSING AND URBAN DEVELOPMENT [Docket No. FR-5916-N-01] 60-Day Notice of Proposed Information Collection: Screening and Eviction for Drug Abuse and Other Criminal Activity AGENCY:

    Office of the Assistant Secretary for Public and Indian Housing, PIH, HUD.

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    Comments Due Date: April 8, 2016.

    ADDRESSES:

    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 [email protected] for a copy of the proposed forms or other available information. Persons with hearing or speech impairments may access this number through TTY by calling the toll-free Federal Relay Service at (800) 877-8339.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.

    A. Overview of Information Collection

    Title of Information Collection: Screening and Eviction for Drug Abuse and Other Criminal Activity.

    OMB Approval Number: 2577-0232.

    Type of Request: Extension of a currently approved collection.

    Form Number: N/A.

    Description of the need for the information and proposed use: The information and collection requirements consist of PHA screening requirements to obtain criminal conviction records from law enforcement agencies to prevent admission of criminals into the public housing and Section 8 programs and to assist in lease enforcement and eviction of those individuals in the public housing and Section 8 programs who engage in criminal activity.

    Respondents (i.e. affected public): State, Local or Tribal Government, Public Housing Agencies, (PHAs), Individuals or Households.

    Estimated Number of Respondents: 3946.

    Estimated Number of Responses: 5,497,832.

    Frequency of Response: 1.

    Average Hours per Response: 1.

    Total Estimated Burdens: 2,118,814 hours.

    B. Solicitation of Public Comment

    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, e.g., permitting electronic submission of responses.

    HUD encourages interested parties to submit comment in response to these questions.

    Authority:

    Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35.

    Dated: January 29, 2016. Merrie Nichols-Dixon, Deputy Director, Office of Policy, Programs and Legislative Initiatives.
    [FR Doc. 2016-02322 Filed 2-5-16; 8:45 am] BILLING CODE 4210-67-P
    DEPARTMENT OF HOUSING AND URBAN DEVELOPMENT [Docket No. FR-5910-N-01] 60-Day Notice of Proposed Information Collection: Validating Estimates of CPD Grantee Accrued Expenses AGENCY:

    The Office of Community Planning and Development, HUD

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    Comments Due Date: April 8, 2016.

    ADDRESSES:

    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 [email protected] for a copy of the proposed forms or other available information. Persons with hearing or speech impairments may access this number through TTY by calling the toll-free Federal Relay Service at (800) 877-8339.

    FOR FURTHER INFORMATION CONTACT:

    David Enzel, Director, OTAM, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410; email [email protected] or telephone 202-402-5557. This is not a toll-free number. Persons with hearing or speech impairments may access this number through TTY by calling the toll-free Federal Relay Service at (800) 877-8339.

    Copies of available documents submitted to OMB may be obtained from Ms. Pollard.

    SUPPLEMENTARY INFORMATION:

    This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.

    A. Overview of Information Collection

    Title of Information Collection: Validating Estimates of CPD Grantee Accrued Expenses.

    OMB Approval Number: 2506—New.

    Type of Request: New.

    Form Number: N/A.

    Description of the need for the information and proposed use:

    Respondents: Grantees.

    Estimated Number of Respondents: 200.

    Estimated Number of Responses: 200.

    Frequency of Response: Yearly.

    Average Hours per Response: 4hrs.

    Total Estimated Burdens: 4hrs.

    Information
  • collection
  • Number of
  • respondents
  • Frequency of
  • response
  • Responses
  • per annum
  • Burden hour per response Annual burden hours Hourly cost per response Annual cost
    200 Annually 200 4 4 0.00 0.00 Total 200 Annually 200 4 4 0.00 0.00
    B. Solicitation of Public Comment

    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, e.g., permitting electronic submission of responses.

    HUD encourages interested parties to submit comment in response to these questions.

    Authority:

    Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35.

    Dated: February 2, 2016. Harriet Tregoning, Principal Deputy Assistant Secretary for Community Planning and Development.
    [FR Doc. 2016-02388 Filed 2-5-16; 8:45 am] BILLING CODE 4210-67-P
    DEPARTMENT OF THE INTERIOR Fish and Wildlife Service [FWS-R5-NCTC-2016-N018; FF09X35000-167-FXGO16610900600] 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 AGENCY:

    Fish and Wildlife Service, Interior.

    ACTION:

    Notice; request for comments.

    SUMMARY:

    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.

    DATES:

    You must submit comments on or before March 9, 2016.

    ADDRESSES:

    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 [email protected] (email). Please provide a copy of your comments to the Service Information Collection Clearance Officer, U.S. Fish and Wildlife Service, MS BPHC, 5275 Leesburg Pike, Falls Church, VA 22041-3803 (mail), or [email protected] (email). Please include “1018-UCAN Survey” in the subject line of your comments.

    FOR FURTHER INFORMATION CONTACT:

    To request additional information about this ICR, contact Hope Grey at [email protected] (email) or 703-358-2482 (telephone). You may review the ICR online at http://www.reginfo.gov. Follow the instructions to review Department of the Interior collections under review by OMB.

    SUPPLEMENTARY INFORMATION:

    Information Collection Request

    OMB Control Number: 1018—New.

    Title: UCAN Survey—National Initiative to Understand and Connect Americans and Nature.

    Service Form Number: None.

    Type of Request: Request for a new OMB control number.

    Description of Respondents: Individuals.

    Estimated Number of Respondents: 8,950.

    Respondent's Obligation: Voluntary.

    Frequency of Collection: One time.

    Estimated Number of Responses: 8,950.

    Completion Time per Response: 20 minutes.

    Estimated Total Annual Burden Hours: 2,983.

    Estimated Annual Nonhour Burden Cost: None.

    Abstract: Nature and the outdoors have always been an important part of the fabric of American life. However, there are major questions about the present and future role of nature and the outdoors in our increasingly diverse, technologically oriented, and rapidly changing society. For our programs to remain relevant to American life today and tomorrow, we must be aware of public sentiment toward the part nature plays in the quality of our lifestyles.

    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 (e.g., outreach and educational programming at national wildlife refuges and national fish hatcheries).

    Comments Received and Our Responses

    On May 19, 2015, we published in the Federal Register (80 FR 28638) a notice of our intent to request that OMB approve this information collection. In that notice, we solicited comments for 60 days, ending on July 20, 2015. We received one comment. The commenter objected to the use of taxpayer dollars for the survey, but did not address the information collection requirements. We did not make any changes to the survey based on this comment.

    Request for Public Comments

    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.

    Dated: February 2, 2016. Tina A. Campbell, Chief, Division of Policy, Performance, and Management Programs, U.S. Fish and Wildlife Service.
    [FR Doc. 2016-02352 Filed 2-5-16; 8:45 am] BILLING CODE 4333-15-P
    DEPARTMENT OF THE INTERIOR Office of the Secretary [15XD5141GM DGM000000.000000 6100.241A0 DN18000000] Proposed Appointment to the National Indian Gaming Commission AGENCY:

    Office of the Secretary, Interior.

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    Submit comments on or before March 9, 2016.

    ADDRESSES:

    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.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    The Indian Gaming Regulatory Act, 25 U.S.C. 2701 et seq., established the National Indian Gaming Commission (Commission), composed of three full-time members. Commission members serve for a term of 3 years. The Chair is appointed by the President with the advice and consent of the Senate. The two associate members are appointed by the Secretary. Before appointing an associate member to the Commission, the Secretary is required to “publish in the Federal Register the name and other information the Secretary deems pertinent regarding a nominee for membership on the Commission and . . . allow a period of not less than thirty days for receipt of public comments.” See 25 U.S.C. 2704(b)(2)(B).

    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.

    Dated: February 2, 2016. Sally Jewell, Secretary of the Interior.
    [FR Doc. 2016-02349 Filed 2-5-16; 8:45 am] BILLING CODE 4334-63-P
    DEPARTMENT OF THE INTERIOR Office of Surface Mining Reclamation and Enforcement [S1D1S SS08011000 SX064A000 167S180110; S2D2S SS08011000 SX064A000 16XS501520] North Cumberland Wildlife Management Area, Tennessee Lands Unsuitable for Mining Draft Petition Evaluation Document and Environmental Impact Statement—OSM-EIS-37 AGENCY:

    Office of Surface Mining Reclamation and Enforcement, Interior.

    ACTION:

    Reopening of the public comment period.

    SUMMARY:

    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.

    DATES:

    Electronic or written comments: OSMRE will accept electronic or written comments, data, and information in response to the draft PED/EIS received no later than February 26, 2016.

    ADDRESSES:

    Comments may be submitted using any of the following methods:

    Electronic Comments: http://www.osmre.gov/programs/rcm/TNLUM.shtm. Please follow the online instructions for submitting comments.

    Mail/Hand-Delivery/Courier: 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.

    You may review the draft PED/EIS online at http://www.osmre.gov/programs/rcm/TNLUM.shtm. You also may review these documents in person at the location listed below.

    FOR FURTHER INFORMATION CONTACT:

    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: [email protected].

    SUPPLEMENTARY INFORMATION:

    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.

    Authority:

    40 CFR 1506.1, 40 CFR 1506.6.

    Dated: February 1, 2016. Thomas D. Shope, Regional Director, Appalachian Region.
    [FR Doc. 2016-02449 Filed 2-5-16; 8:45 am] BILLING CODE 4310-05-P
    INTERNATIONAL TRADE COMMISSION [Investigation No. 731-TA-125 (Fourth Review)] Potassium Permanganate From China Determination

    On the basis of the record 1 developed in the subject five-year review, the United States International Trade Commission (“Commission”) determines, pursuant to the Tariff Act of 1930, that revocation of the antidumping duty order on Potassium Permanganate from China would be likely to lead to continuation or recurrence of material injury to an industry in the United States within a reasonably foreseeable time.

    1 The record is defined in sec. 207.2(f) of the Commission's Rules of Practice and Procedure (19 CFR 207.2(f)).

    Background

    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, 2016.2 The views of the Commission are contained in USITC Publication 4590 (January 2016), entitled Potassium Permanganate from China: Investigation No. 731-TA-125 (Fourth Review).

    2 The Commission has the authority to toll statutory deadlines during a period when the federal government is closed. Because the Commission was closed on January 25 and 26, 2016 due to inclement weather in Washington, DC, the Commission tolled the statutory deadline in this review by two days.

    By order of the Commission.

    Issued: February 2, 2016. Lisa R. Barton, Secretary to the Commission.
    [FR Doc. 2016-02344 Filed 2-5-16; 8:45 am] BILLING CODE 7020-02-P
    INTERNATIONAL TRADE COMMISSION Notice of Receipt of Complaint; Solicitation of Comments Relating to the Public Interest AGENCY:

    U.S. International Trade Commission.

    ACTION:

    Notice.

    SUMMARY:

    Notice is hereby given that the U.S. International Trade Commission has received a complaint entitled Certain Hospital Beds, and Components Thereof DN 3117; the Commission is soliciting comments on any public interest issues raised by the complaint or complainant's filing under section 210.8(b) of the Commission's Rules of Practice and Procedure (19 CFR 210.8(b)).

    FOR FURTHER INFORMATION CONTACT:

    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.1 and will be available for inspection during official business hours (8:45 a.m. to 5:15 p.m.) in the Office of the Secretary, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 205-2000.

    1 Electronic Document Information System (EDIS): http://edis.usitc.gov.

    General information concerning the Commission may also be obtained by accessing its Internet server at United States International Trade Commission (USITC) at USITC.2 The public record for this investigation may be viewed on the Commission's Electronic Document Information System (EDIS) at EDIS.3 Hearing-impaired persons are advised that information on this matter can be obtained by contacting the Commission's TDD terminal on (202) 205-1810.

    2 United States International Trade Commission (USITC): http://edis.usitc.gov.

    3 Electronic Document Information System (EDIS): http://edis.usitc.gov.

    SUPPLEMENTARY INFORMATION:

    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 Federal Register. There will be further opportunities for comment on the public interest after the issuance of any final initial determination in this investigation.

    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. (See Handbook for Electronic Filing Procedures, Electronic Filing Procedures 4 ). Persons with questions regarding filing should contact the Secretary (202-205-2000).

    4 Handbook for Electronic Filing Procedures: http://www.usitc.gov/secretary/fed_reg_notices/rules/handbook_on_electronic_filing.pdf.

    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. See 19 CFR 201.6. Documents for which confidential treatment by the Commission is properly sought will be treated accordingly. All nonconfidential written submissions will be available for public inspection at the Office of the Secretary and on EDIS 5 .

    5 Electronic Document Information System (EDIS): http://edis.usitc.gov.

    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.

    Dated: February 2, 2016. Lisa R. Barton, Secretary to the Commission.
    [FR Doc. 2016-02296 Filed 2-5-16; 8:45 am] BILLING CODE 7020-02-P
    DEPARTMENT OF JUSTICE [OMB Number 1121-0240] 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 AGENCY:

    Bureau of Justice Statistics, Department of Justice.

    ACTION:

    60-Day notice.

    SUMMARY:

    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.

    DATES:

    Comments are encouraged and will be accepted for 60 days until April 8, 2016.

    FOR FURTHER INFORMATION CONTACT:

    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: [email protected]; telephone: 202-616-1706).

    SUPPLEMENTARY INFORMATION:

    Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:

    —Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the Bureau of Justice Statistics, including whether the information will have practical utility; —Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; —Evaluate whether and if so how the quality, utility, and clarity of the information to be collected can be enhanced; and —Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.

    Overview of this information collection:

    (1) Type of Information Collection: Reinstatement of the Law Enforcement Management and Administrative Statistics (LEMAS) Survey, with changes, a previously approved collection for which approval has expired.

    (2) The Title of the Form/Collection: 2016 Law Enforcement Management and Administrative Statistics Survey.

    (3) The agency form number, if any, and the applicable component of the Department sponsoring the collection: The form number for the questionnaire is CJ-44. The applicable component within the Department of Justice is the Bureau of Justice Statistics, in the Office of Justice Programs.

    (4) Affected public who will be asked or required to respond, as well as a brief abstract: Respondents will be general purpose state, county and local law enforcement agencies (LEAs), including local and county police departments, sheriff's offices, and primary state law enforcement agencies. Since 1987, BJS has collected information about the personnel, policies, and practices of law enforcement agencies via the Law Enforcement Management and Administrative Statistics (LEMAS) survey. This core survey, which has been administered every 4 to 6 years, has been used to produce nationally representative estimates on the demographic characteristics of sworn personnel, hiring practices, operations, equipment, technology, and agency policies and procedures. BJS plans to publish this information in reports and reference it when responding to queries from the U.S. Congress, Executive Office of the President, the U.S. Supreme Court, state officials, international organizations, researchers, students, the media, and others interested in criminal justices statistics.

    (5) An estimate of the total number of respondents and the amount of time estimated for an average respondent to respond: An agency-level survey will be sent to approximately 3,497 LEA respondents. The expected burden placed on these respondents is about 2.65 hours per respondent. The burden estimate is based on data from prior administrations of the LEMAS.

    (6) An estimate of the total public burden (in hours) associated with the collection: There is an estimated 9,269 total burden hours associated with this collection.

    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.

    Dated: February 3, 2016. Jerri Murray, Department Clearance Officer for PRA, U.S. Department of Justice.
    [FR Doc. 2016-02378 Filed 2-5-16; 8:45 am] BILLING CODE 4410-18-P
    DEPARTMENT OF JUSTICE [OMB Number 1110-0026] 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 AGENCY:

    Federal Bureau of Investigation, Department of Justice.

    ACTION:

    60-day notice.

    SUMMARY:

    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.

    DATES:

    Comments are encouraged and will be accepted for 60 days until April 8, 2016.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:

    —Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the Bureau of Justice Statistics, including whether the information will have practical utility; —Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; —Evaluate whether and if so how the quality, utility, and clarity of the information to be collected can be enhanced; and —Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.

    Overview of this information collection:

    1. Type of Information Collection: Extension with change of a currently approved collection.

    2. The Title of the Form/Collection: Federal Firearms Licensee (FFL) Enrollment/National Instant Criminal Background Check System (NICS) E-Check Enrollment Form, Federal Firearms Licensee (FFL) Officer/Employee Acknowledgment of Responsibilities under the NICS form.

    3. The agency form number, if any, and the applicable component of the Department sponsoring the collection: The form is unnumbered

    4. Affected public who will be asked or required to respond, as well as a brief abstract:

    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. An estimate of the total number of respondents and the amount of time estimated for an average respondent to respond: The completion of the Federal Firearms Licensee (FFL) Enrollment/National Instant Criminal Background Check System (NICS) E-Check Enrollment Form is estimated that there are 406 respondents each month, 4,872 (406 × 12) annual responses, and that each response takes approximately two minutes, time to complete the form is estimated to be three minutes; and the time to assemble, mail, or fax the form to the FBI is estimated to be three minutes, for a total of 8 minutes per form. Total completion time is 4,872 × 8/60 = 650 hours.

    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. An estimate of the total public burden (in hours) associated with the collection: The entire process of reading the letter and completing both forms would take 15 minutes per respondent. The average hour burden for completing both forms and reading the accompanying letter would be 4,872 × 15/60 = 1,218 hours.

    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.

    Dated: February 3, 2016. Jerri Murray, Department Clearance Officer for PRA, U.S. Department of Justice.
    [FR Doc. 2016-02377 Filed 2-5-16; 8:45 am] BILLING CODE 4410-02-P
    DEPARTMENT OF LABOR Office of the Secretary Agency Information Collection Activities; Submission for OMB Review; Comment Request; Department of Labor Generic Solution for “Touch-Base” Activities ACTION:

    Notice.

    SUMMARY:

    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 et seq.). Public comments on the ICR are invited.

    DATES:

    The OMB will consider all written comments that agency receives on or before March 9, 2016.

    ADDRESSES:

    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 http://www.reginfo.gov/public/do/PRAViewICR?ref_nbr=201601-1225-004 or by contacting Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to [email protected].

    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: [email protected]. Commenters are encouraged, but not required, to send a courtesy copy of any comments by mail or courier to the U.S. Department of Labor-OASAM, Office of the Chief Information Officer, Attn: Departmental Information Compliance Management Program, Room N1301, 200 Constitution Avenue NW., Washington, DC 20210; or by email: [email protected].

    FOR FURTHER INFORMATION CONTACT:

    Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to [email protected].

    Authority:

    44 U.S.C. 3507(a)(1)(D).

    SUPPLEMENTARY INFORMATION:

    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. See 5 CFR 1320.5(a) and 1320.6. The DOL obtains OMB approval for this information collection under Control Number 1225-0059. The DOL notes that existing information collection requirements submitted to the OMB receive a month-to-month extension while they undergo review. New requirements would only take effect upon OMB approval.

    Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the ADDRESSES section within thirty (30) days of publication of this notice in the Federal Register. In order to help ensure appropriate consideration, comments should mention OMB Control Number 1225-0059. The OMB is particularly interested in comments that:

    • 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, e.g., permitting electronic submission of responses.

    Agency: DOL-OASAM.

    Title of Collection: Department of Labor Generic Solution for “Touch-Base” Activities.

    OMB Control Number: 1225-0059.

    Affected Public: State, Local, and Tribal Governments; Individuals or Households; and Private Sector—businesses or other for-profits, farms, and not-for-profit institutions.

    Total Estimated Number of Respondents: 800,000.

    Total Estimated Number of Responses: 800,000.

    Total Estimated Annual Time Burden: 80,000 hours.

    Total Estimated Annual Other Costs Burden: $0.

    Dated: January 29, 2016. Michel Smyth, Departmental Clearance Officer.
    [FR Doc. 2016-02433 Filed 2-5-16; 8:45 am] BILLING CODE 4510-04-P
    DEPARTMENT OF LABOR Office of the Secretary Agency Information Collection Activities; Submission for OMB Review; Comment Request; Petitions for Modification of Mandatory Safety Standards ACTION:

    Notice.

    SUMMARY:

    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 et seq. Public comments on the ICR are invited.

    DATES:

    The OMB will consider all written comments that agency receives on or before March 9, 2016.

    ADDRESSES:

    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: http://www.reginfo.gov/public/do/PRAViewICR?ref_nbr=201509-1219-002 or by contacting Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or by email at [email protected].

    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: [email protected]. Commenters are encouraged, but not required, to send a courtesy copy of any comments by mail or courier to the U.S. Department of Labor-OASAM, Office of the Chief Information Officer, Attn: Departmental Information Compliance Management Program, Room N1301, 200 Constitution Avenue NW., Washington, DC 20210; or by email: [email protected].

    FOR FURTHER INFORMATION CONTACT:

    Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or by email at [email protected].

    Authority:

    44 U.S.C. 3507(a)(1)(D).

    SUPPLEMENTARY INFORMATION:

    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. See 30 U.S.C. 811(a), (c); 813(h).

    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. See 5 CFR 1320.5(a) and 1320.6. The DOL obtains OMB approval for this information collection under Control Number 1219-0065.

    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 Federal Register on July 17, 2015 (80 FR 42549).

    Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the ADDRESSES section within thirty (30) days of publication of this notice in the Federal Register. In order to help ensure appropriate consideration, comments should mention OMB Control Number 1219-0065. The OMB is particularly interested in comments that:

    • 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, e.g., permitting electronic submission of responses.

    Agency: DOL-MSHA.

    Title of Collection: Petitions for Modification of Mandatory Safety Standards.

    OMB Control Number: 1219-0065.

    Affected Public: Private Sector—businesses or other for profits and not-for-profit institutions.

    Total Estimated Number of Respondents: 68.

    Total Estimated Number of Responses: 68.

    Total Estimated Annual Time Burden: 2,720 hours.

    Total Estimated Annual Other Costs Burden: $24,916.

    Dated: January 29, 2016. Michel Smyth, Departmental Clearance Officer.
    [FR Doc. 2016-02426 Filed 2-5-16; 8:45 am] BILLING CODE 4510-43-P
    DEPARTMENT OF LABOR Office of the Secretary Agency Information Collection Activities; Submission for OMB Review; Comment Request; Short-Time Compensation Grants ACTION:

    Notice.

    SUMMARY:

    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 in accordance with the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501 et seq.). Public comments on the ICR are invited.

    DATES:

    The OMB will consider all written comments that agency receives on or before March 9, 2016.

    ADDRESSES:

    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 http://www.reginfo.gov/public/do/PRAViewICR?ref_nbr=201508-1205-010 (this link will only become active on the day following publication of this notice) or by contacting Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to [email protected].

    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: [email protected]. Commenters are encouraged, but not required, to send a courtesy copy of any comments by mail or courier to the U.S. Department of Labor-OASAM, Office of the Chief Information Officer, Attn: Departmental Information Compliance Management Program, Room N1301, 200 Constitution Avenue NW., Washington, DC 20210; or by email: [email protected].

    FOR FURTHER INFORMATION CONTACT:

    Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to [email protected].

    Authority:

    44 U.S.C. 3507(a)(1)(D).

    SUPPLEMENTARY INFORMATION:

    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. See 5 CFR 1320.5(a) and 1320.6. The DOL obtains OMB approval for this information collection under Control Number 1205-0499. This information collection is scheduled to expire on February 29, 2016; however, the DOL notes that existing information collection requirements submitted to the OMB receive a month-to-month extension while they undergo review. New requirements would only take effect upon OMB approval. For additional substantive information about this ICR, see the related notice published in the Federal Register on June 26, 2015.

    Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the ADDRESSES section within thirty (30) days of publication of this notice in the Federal Register. In order to help ensure appropriate consideration, comments should mention OMB Control Number 1205-0499. The OMB is particularly interested in comments that:

    • 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, e.g., permitting electronic submission of responses.

    Agency: DOL-ETA.

    Title of Collection: Short-Time Compensation Grants.

    OMB Control Number: 1205-0499.

    Affected Public: State, Local, and Tribal Governments.

    Total Estimated Number of Respondents: 17.

    Total Estimated Number of Responses: 68.

    Total Estimated Annual Time Burden: 68 hours.

    Total Estimated Annual Other Costs Burden: $0.

    Dated: January 29, 2016. Michel Smyth, Departmental Clearance Officer.
    [FR Doc. 2016-02423 Filed 2-5-16; 8:45 am] BILLING CODE 4510-FW-P
    DEPARTMENT OF LABOR Office of the Secretary Agency Information Collection Activities; Submission for OMB Review; Comment Request; Self-Employment Training Demonstration Evaluation ACTION:

    Notice.

    SUMMARY:

    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 et seq.). Public comments on the ICR are invited.

    DATES:

    The OMB will consider all written comments that agency receives on or before March 9, 2016.

    ADDRESSES:

    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 http://www.reginfo.gov/public/do/PRAViewICR?ref_nbr=201512-1205-005 (this link will only become active on the day following publication of this notice) or by contacting Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to [email protected].

    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: [email protected]. Commenters are encouraged, but not required, to send a courtesy copy of any comments by mail or courier to the U.S. Department of Labor-OASAM, Office of the Chief Information Officer, Attn: Departmental Information Compliance Management Program, Room N1301, 200 Constitution Avenue NW., Washington, DC 20210; or by email: [email protected].

    FOR FURTHER INFORMATION CONTACT:

    Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or sending an email to [email protected].

    Authority:

    44 U.S.C. 3507(a)(1)(D).

    SUPPLEMENTARY INFORMATION:

    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. See 5 CFR 1320.5(a) and 1320.6. The DOL obtains OMB approval for this information collection under Control Number 1205-0505. The DOL notes that existing information collection requirements submitted to the OMB receive a month-to-month extension while they undergo review. New requirements would only take effect upon OMB approval. For additional substantive information about this ICR, see the related notice published in the Federal Register on October 16, 2015 (80 FR 62572).

    Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the ADDRESSES section within thirty (30) days of publication of this notice in the Federal Register. In order to help ensure appropriate consideration, comments should mention OMB Control Number 1205-0505. The OMB is particularly interested in comments that:

    • 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, e.g., permitting electronic submission of responses.

    Agency: DOL-ETA.

    Title of Collection: Self-Employment Training Demonstration Evaluation.

    OMB Control Number: 1205-0505.

    Affected Public: Individuals and Households; State, Local, and Tribal Governments.

    Total Estimated Number of Respondents: 1,080.

    Total Estimated Number of Responses: 1,080.

    Total Estimated Annual Time Burden: 360 hours.

    Total Estimated Annual Other Costs Burden: $0.

    Dated: January 29, 2016. Michel Smyth, Departmental Clearance Officer.
    [FR Doc. 2016-02428 Filed 2-5-16; 8:45 am] BILLING CODE 4510-FT-P
    NATIONAL SCIENCE FOUNDATION Notice of Intent To Seek Approval To Establish an Information Collection AGENCY:

    National Science Foundation.

    ACTION:

    Notice and request for comments.

    SUMMARY:

    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.

    DATES:

    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.

    For Additional Information or Comments:

    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 [email protected]. Individuals who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339, which is accessible 24 hours a day, 7 days a week, 365 days a year (including federal holidays). You also may obtain a copy of the data collection instrument and instructions from Ms. Plimpton.

    SUPPLEMENTARY INFORMATION:

    Title of Collection: Awardee Reporting Requirements for the Experimental Program to Stimulate Competitive Research (EPSCoR) Research Infrastructure Improvement Programs.

    OMB Number: 3145—NEW.

    Expiration Date of Approval: Not applicable.

    Type of Request: Intent to seek approval to establish an information collection.

    Abstract Proposed Project

    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 Board task force analyzed the geographic distribution of NSF funds, which resulted in the creation of an NSF Experimental Program to Stimulate Competitive Research (EPSCoR). Congress specified two objectives for the EPSCoR program in the National Science Foundation Authorization Act of 1988: (1) To assist States that historically have received relatively little Federal research and development funding; and (2) to assist States that have demonstrated a commitment to develop their research bases and improve science and engineering research and education programs at their universities and colleges.

    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.

    Use of the Information: NSF will use the information to continue funding of the EPSCoR RII projects, and to evaluate the progress of the program.

    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.

    Estimate of Burden: 100 hours per project for twenty-nine projects for a total of 2,900 hours.

    Respondents: Non-profit institutions; federal government.

    Estimated Number of Responses per Report: One.

    Comments: Comments are invited on (a) whether the proposed collection of information is necessary for the proper performance of the functions of the Agency, including whether the information shall have practical utility; (b) the accuracy of the Agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information on respondents, including through the use of automated collection techniques or other forms of information technology; and (d) ways to minimize the burden of the collection of information on 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.

    Dated: February 2, 2016. Suzanne H. Plimpton, Reports Clearance Officer, National Science Foundation.
    [FR Doc. 2016-02365 Filed 2-5-16; 8:45 am] BILLING CODE 7555-01-P
    NUCLEAR REGULATORY COMMISSION [Docket Nos. 50-445, 50-446, and 72-74; NRC-2016-0020] 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 AGENCY:

    Nuclear Regulatory Commission.

    ACTION:

    Application for direct transfer of licenses; opportunity to comment, request a hearing, and petition for leave to intervene.

    SUMMARY:

    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 Operating License Nos. NPF-87 and NPF-89 for Comanche Peak Nuclear Power Plant, Units 1 and 2 (CPNPP), and general license for independent spent fuel storage installation (ISFSI) from the current holder, Luminant Power, to as yet unnamed companies, herein identified as Comanche Peak LLC (CP LLC), as owner, and Operating Company LLC (OpCo LLC), as operator. Both the units are Pressurized Water Reactor design, 3612 megawatts thermal units, located in Somervell County, Texas. The ISFSI is also located within a separate protected area collocated at the CPNPP site. The NRC is also considering amending the facility operating licenses for administrative purposes to reflect the proposed transfer.

    DATES:

    Comments must be filed by March 9, 2016. A request for a hearing must be filed by February 29, 2016.

    ADDRESSES:

    You may submit comments by any of the following methods (unless this document describes a different method for submitting comments on a specific subject):

    Federal Rulemaking Web site: Go to http://www.regulations.gov and search for Docket ID NRC-2016-0020. Address questions about NRC dockets to Carol Gallagher; telephone: 301-415-3463; email: [email protected]. For technical questions contact the individual listed in the FOR FURTHER INFORMATION CONTACT section of this document.

    Email comments to: [email protected]. If you do not receive an automatic email reply confirming receipt, then contact us at 301-415-1677.

    Fax comments to: Secretary, U.S. Nuclear Regulatory Commission at 301-415-1101.

    Mail comments to: Secretary, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, ATTN: Rulemakings and Adjudications Staff.

    Hand deliver comments to: 11555 Rockville Pike, Rockville, Maryland 20852, between 7:30 a.m. and 4:15 p.m. (Eastern Time) Federal workdays; telephone: 301-415-1677.

    For additional direction on obtaining information and submitting comments, see “Obtaining Information and Submitting Comments” in the SUPPLEMENTARY INFORMATION section of this document.

    FOR FURTHER INFORMATION CONTACT:

    Balwant K. Singal, Office of the Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-3016, email: [email protected].

    SUPPLEMENTARY INFORMATION:

    I. Obtaining Information and Submitting Comments A. Obtaining Information

    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:

    Federal Rulemaking Web site: Go to http://www.regulations.gov and search for Docket ID NRC-2016-0020.

    NRC's Agencywide Documents Access and Management System (ADAMS): You may obtain publicly-available documents online in the ADAMS Public Documents collection at http://www.nrc.gov/reading-rm/adams.html. To begin the search, select “ADAMS Public Documents” and then select “Begin Web-based ADAMS Search.” For problems with ADAMS, please contact the NRC's Public Document Room (PDR) reference staff at 1-800-397-4209, 301-415-4737, or by email to [email protected]. The application for direct transfer of the licenses dated November 12 and December 9, 2015, is available in ADAMS under Accession Nos. ML15320A093 and ML15345A048, respectively.

    NRC's PDR: You may examine and purchase copies of public documents at the NRC's PDR, Room O1-F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852.

    B. Submitting Comments.

    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 http://www.regulations.gov as well as enter the comment submissions into ADAMS. The NRC does not routinely edit comment submissions to remove identifying or contact information.

    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.

    II. Introduction

    The NRC is considering the issuance of an order under § 50.80 of title 10 of the Code of Federal Regulations (10 CFR), approving the direct transfer of control of CPNPP and ISFSI, Facility Operating License Nos. NPF-87 and NPF-89, currently held by Luminant Power. Luminant Power is owned by Energy Future Competitive Holdings Company LLC (EFCH), through its wholly owned subsidiaries. The EFCH is a direct wholly owned subsidiary of Energy Future Holdings Corporation (EFH). According to the application, the current and intended ownership structure of the facility is depicted in simplified organization charts provided in Exhibits A and B of the letter dated November 12, 2015. As a result of the proposed transactions and consistent with Exhibit B, EFH and EFCH will no longer ultimately own the facility. Rather, at the emergence from the bankruptcy, Reorganized Texas Competitive Electric Holdings (TCEH) Corporation (Reorganized TCEH), the ultimate parent company of CP LLC, will be ultimately owned by numerous and diverse set of independent and unaffiliated stockholders. No single entity is expected to own a majority of, or exercise control over Reorganized TCEH or its board of directors. The licenses will be transferred from Luminant Power to CP LLC, as owner, and OpCo LLC, as operator. Luminant Power has committed to inform the NRC staff of the final legal entity names and submit updated operating license revision pages, as and when, the final legal names are selected before the issuance of the license transfer. The NRC is also considering amending the facility operating licenses for administrative purposes to reflect the proposed transfer.

    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 gives its consent in writing. The Commission will approve an application for the direct transfer of a license if the Commission determines that the proposed transferee is qualified to hold the license, and that the transfer is otherwise consistent with applicable provisions of law, regulations, and orders issued by 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.

    III. Opportunity To Comment

    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 ADDRESSES section of this document.

    IV. Opportunity To Request a Hearing and Petition for Leave To Intervene

    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 http://www.nrc.gov/reading-rm/doc-collections/cfr/. If a request for a hearing or petition for leave to intervene is filed within 20 days, the Commission or a presiding officer designated by the Commission or by the Chief Administrative Judge of the Atomic Safety and Licensing Board Panel, will rule on the request and/or petition; and the Secretary or the Chief Administrative Judge of the Atomic Safety and Licensing Board will issue a notice of a hearing or an appropriate order.

    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 section, except that under § 2.309(h)(2) a State, local governmental body, or Federally-recognized Indian Tribe, or agency thereof does not need to address the standing requirements in 10 CFR 2.309(d) if the facility is located within its boundaries. A State, local governmental body, Federally-recognized Indian Tribe, or agency thereof may also have the opportunity to participate under 10 CFR 2.315(c).

    If a hearing is granted, any person who does not wish, or is not qualified, to become a party to the proceeding may, in the discretion of the presiding officer, be permitted to make a limited appearance pursuant to the provisions of 10 CFR 2.315(a). A person making a limited appearance may make an oral or written statement of position on the issues, but may not otherwise participate in the proceeding. A limited appearance may be made at any session of the hearing or at any prehearing conference, subject to the limits and conditions as may be imposed by the presiding officer. Persons desiring to make a limited appearance are requested to inform the Secretary of the Commission by February 29, 2016.

    V. Electronic Submissions (E-Filing)

    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 [email protected], or by telephone at 301-415-1677, to request (1) a digital identification (ID) certificate, which allows the participant (or its counsel or representative) to digitally sign documents and access the E-Submittal server for any proceeding in which it is participating; and (2) advise the Secretary that the participant will be submitting a request or petition for hearing (even in instances in which the participant, or its counsel or representative, already holds an NRC-issued digital ID certificate). Based upon this information, the Secretary will establish an electronic docket for the hearing in this proceeding if the Secretary has not already established an electronic docket.

    Information about applying for a digital ID certificate is available on the NRC's public Web site at http://www.nrc.gov/site-help/e-submittals/getting-started.html. System requirements for accessing the E-Submittal server are detailed in the NRC's “Guidance for Electronic Submission,” which is available on the agency's public Web site at http://www.nrc.gov/site-help/e-submittals.html. Participants may attempt to use other software not listed on the Web site, but should note that the NRC's E-Filing system does not support unlisted software, and the NRC Meta System Help Desk will not be able to offer assistance in using unlisted software.

    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 http://www.nrc.gov/site-help/e-submittals.html.

    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 http://www.nrc.gov/site-help/e-submittals.html. A filing is considered complete at the time the documents are submitted through the NRC's E-Filing system. To be timely, an electronic filing must be submitted to the E-Filing system no later than 11:59 p.m. Eastern Time on the due date. Upon receipt of a transmission, the E-Filing system time-stamps the document and sends the submitter an email notice confirming receipt of the document. The E-Filing system also distributes an email notice that provides access to the document to the NRC's Office of the General Counsel and any others who have advised the Office of the Secretary that they wish to participate in the proceeding, so that the filer need not serve the documents on those participants separately. Therefore, applicants and other participants (or their counsel or representative) must apply for and receive a digital ID certificate before a hearing request/petition to intervene is filed so that they can obtain access to the document via the E-Filing system.

    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 http://www.nrc.gov/site-help/e-submittals.html, by email to [email protected], or by a toll-free call at 1-866-672-7640. The NRC Meta System Help Desk is available between 8 a.m. and 8 p.m., Eastern Time, Monday through Friday, excluding government holidays.

    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 http://ehd1.nrc.gov/ehd/, unless excluded pursuant to an order of the Commission, or the presiding officer. Participants are requested not to include personal privacy information, such as social security numbers, home addresses, or home phone numbers in their filings, unless an NRC regulation or other law requires submission of such information. However, in some instances, a request to intervene will require including information on local residence in order to demonstrate a proximity assertion of interest in the proceeding. With respect to copyrighted works, except for limited excerpts that serve the purpose of the adjudicatory filings and would constitute a Fair Use application, participants are requested not to include copyrighted materials in their submission.

    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 Federal Register and served on the parties to the hearing.

    For further details with respect to this application, see the letters dated November 12 and December 9, 2015.

    Dated at Rockville, Maryland, this 27th day of January 2016.

    For the Nuclear Regulatory Commission.

    Balwant K. Singal, Senior Project Manager, Plant Licensing Branch IV-1, Division of Operating Reactor Licensing, Office of Nuclear Reactor Regulation.
    [FR Doc. 2016-02380 Filed 2-5-16; 8:45 am] BILLING CODE 7590-01-P
    NUCLEAR REGULATORY COMMISSION [Docket No. 72-17; NRC-2016-0021] Portland General Electric Company; Trojan Independent Spent Fuel Storage Installation in Columbia County, Oregon AGENCY:

    Nuclear Regulatory Commission.

    ACTION:

    Environmental assessment and finding of no significant impact; issuance.

    SUMMARY:

    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).

    ADDRESSES:

    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:

    Federal Rulemaking Web site: Go to http://www.regulations.gov and search for Docket ID NRC-2016-0021. Address questions about NRC dockets to Carol Gallagher; telephone: 301-415-3463; email: [email protected]. For technical questions, contact the individual listed in the FOR FURTHER INFORMATION CONTACT section of this document.

    NRC's Agencywide Documents Access and Management System (ADAMS): You may obtain publicly-available documents online in the ADAMS Public Documents collection at http://www.nrc.gov/reading-rm/adams.html. To begin the search, select “ADAMS Public Documents” and then select “Begin Web-based ADAMS Search.” For problems with ADAMS, please contact the NRC's Public Document Room (PDR) reference staff at 1-800-397-4209, 301-415-4737, or by email to [email protected]. The ADAMS accession number for each document referenced (if it available in ADAMS) is provided the first time that a document is referenced. In addition, for the convenience of the reader, the ADAMS accession numbers are provided in a table in the, “Availability of Documents” section of this document.

    NRC's PDR: You may examine and purchase copies of public documents at the NRC's PDR, Room O1-F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852.

    FOR FURTHER INFORMATION CONTACT:

    Jose Cuadrado, Office of Nuclear Material Safety and Safeguards, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-0606, email: [email protected].

    SUPPLEMENTARY INFORMATION: I. Introduction

    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 Code of Federal Regulations (10 CFR), “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions,” which implement the National Environmental Policy Act of 1969, as amended (42 U.S.C. 4321 et seq.). Based on the EA, the NRC staff has determined that approval of the DFP for the Trojan ISFSI will not significantly affect the quality of the human environment, and, accordingly, the staff has concluded that a FONSI is appropriate. The NRC staff further finds that preparation of an environmental impact statement (EIS) is not warranted.

    II. Environmental Assessment Summary Background

    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 Federal Register amending its decommissioning planning regulations. The final rule amended the NRC's regulation in 10 CFR 72.30, which concerns financial assurance and decommissioning for ISFSIs. This regulation now requires each holder of, or applicant for, a license under 10 CFR part 72 to submit, for NRC's review and approval, a DFP. The purpose of the DFP is to demonstrate the licensee's financial assurance, i.e., that funds will be available to decommission the ISFSI. The NRC staff is reviewing the DFP submitted by PGE on December 13, 2012. Specifically, the NRC must determine whether PGE's DFP contains the information required by 10 CFR 72.30(b) and whether PGE has provided reasonable assurance that funds will be available to decommission the ISFSI.

    Proposed Action

    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 financial assurance to cover the DCE and that the financial instruments meet the criteria of 10 CFR 72.30(e).

    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.

    Purpose and Need for the Proposed Action

    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).

    Environmental Impacts of the Proposed Action

    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.

    Alternative to the Proposed Action

    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.

    Agencies and Persons Consulted

    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.

    III. Finding of No Significant Impact

    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.

    IV. Availability of Documents Date Document ADAMS
  • Accession No.
  • December 13, 2012 Submission of PGE's decommissioning funding plan ML12355A286 February 1, 2009 Environmental Assessment for Final Rule—Decommissioning Planning ML090500648 January 20, 2016 NRC staff's EA for the approval of the decommissioning funding plan ML16029A242

    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 ADDRESSES section of this document.

    Dated at Rockville, Maryland, this 1st day of February, 2016.

    For the Nuclear Regulatory Commission.

    Steve Ruffin, Acting Branch Chief, Spent Fuel Licensing Branch, Division of Spent Fuel Management, Office of Nuclear Material Safety and Safeguards.
    [FR Doc. 2016-02381 Filed 2-5-16; 8:45 am] BILLING CODE 7590-01-P
    NUCLEAR REGULATORY COMMISSION Advisory Committee on the Medical Uses of Isotopes: Meeting Notice AGENCY:

    U.S. Nuclear Regulatory Commission.

    ACTION:

    Notice of meeting.

    SUMMARY:

    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 Code of Federal Regulations (10 CFR) Section 35.390) Subcommittee. This report will include the subcommittee's recommendation for the total number of training and experience hours for authorized users for 35.390 that is necessary for safety. Meeting information, including a copy of the agenda and handouts, will be available at http://www.nrc.gov/reading-rm/doc-collections/acmui/meetings/2016.html. The agenda and handouts may also be obtained by contacting Ms. Sophie Holiday using the information below.

    DATES:

    The teleconference meeting will be held on Thursday, March 10, 2016, 1:30 p.m. to 3:30 p.m. Eastern Time.

    Public Participation: Any member of the public who wishes to participate in the teleconference should contact Ms. Holiday using the contact information below.

    Contact Information: Sophie Holiday, email: [email protected], telephone: (301) 415-7865.

    Conduct of the Meeting

    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 http://www.nrc.gov/reading-rm/doc-collections/acmui/meetings/2016.html on or about April 21, 2016.

    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.

    Dated at Rockville, Maryland, this 2nd day of February 2016. Andrew L. Bates, Advisory Committee Management Officer.
    [FR Doc. 2016-02382 Filed 2-5-16; 8:45 am] BILLING CODE 7590-01-P
    SECURITIES AND EXCHANGE COMMISSION Proposed Collection; Comment Request Upon Written Request Copies Available From: Securities and Exchange Commission, Office of FOIA Services, 100 F Street NE., Washington, DC 20549-0213. Extension: Form F-8. SEC File No. 270-332, OMB Control No. 3235-0378.

    Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.), the Securities and Exchange Commission (“Commission”) is soliciting comments on the collection of information summarized below. The Commission plans to submit this existing collection of information to the Office of Management and Budget for extension and approval.

    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 et seq.) that will be used in an exchange offer or business combination. The information collected is intended to ensure that the information required to be filed by the Commission permits verification of compliance with securities law requirements and assures the public availability of such information. We estimate that Form F-8 takes approximately one hour per response to prepare and is filed by approximately 5 respondents. We estimate that 25% of one hour per response (15 minutes) is prepared by the company for a total annual reporting burden of one hour (15 minutes/60 minutes per response × 5 responses = 1.25 hours rounded to the nearest whole number one hour).

    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: [email protected].

    Dated: February 2, 2016. Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02339 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION Proposed Collection; Comment Request Upon Written Request, Copies Available From: Securities and Exchange Commission, Office of FOIA Services, 100 F Street NE., Washington, DC 20549-2736. Extension: Rule 15b1-1/Form BD; SEC File No. 270-19, OMB Control No. 3235-0012.

    Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (“PRA”) (44 U.S.C. 3501 et seq.), the Securities and Exchange Commission (“Commission”) is soliciting comments on the collection of information provided for in Rule 15b1-1 (17 CFR 240.15b1-1) and Form BD (17 CFR 249.501) under the Securities Exchange Act of 1934 (17 U.S.C. 78a et seq.). The Commission plans to submit this existing collection of information to the Office of Management and Budget (“OMB”) for extension and approval.

    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: [email protected].

    Dated: February 2, 2016. Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02340 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION [Release No. 34-77036; File No. SR-EDGX-2016-01] 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 February 2, 2016.

    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),1 and Rule 19b-4 thereunder,2 notice is hereby given that on January 21, 2016, EDGX Exchange, Inc. (the “Exchange” or “EDGX”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change as described in Items I and II below, which Items have been prepared by the Exchange. The Exchange has designated this proposal as a “non-controversial” proposed rule change pursuant to Section 19(b)(3)(A) of the Act 3 and Rule 19b-4(f)(6)(iii) thereunder,4 which renders it effective upon filing with the Commission. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.

    1 15 U.S.C. 78s(b)(1).

    2 17 CFR 240.19b-4.

    3 15 U.S.C. 78s(b)(3)(A).

    4 17 CFR 240.19b-4(f)(6)(iii).

    I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change

    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.5

    5 17 CFR 240.19b-4(f)(6)(iii).

    The text of the proposed rule change is available at the Exchange's Web site at www.batstrading.com, at the principal office of the Exchange, and at the Commission's Public Reference Room.

    II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change

    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.

    (A) Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose

    The Exchange is proposing to modify Rule 21.1, Definitions, which sets forth the various definitions applicable to the operation of the EDGX Options platform, including order types and order type modifiers accepted by EDGX Options. As set forth in Rule 21.1, an order can be attributed on EDGX Options, meaning that such order is displayed with not only a price and size but also a User's 6 market participant identifier, or MPID (such order an “Attributable Order”). Alternatively, a User may also submit an order that is designated for display on an anonymous basis, a “Non-Attributable Order.” Rule 21.1(c) also states that all orders shall be treated as Attributable Orders unless a User has entered instructions to treat such orders as Non-Attributable Orders. In addition to attribution, as discussed in Rule 21.1, Exchange Rule 21.15(c) states that the Exchange will indicate on OPRA when there is Customer interest on EDGX Options and will identify Customer orders and trades as such on the Exchange's proprietary data feeds.

    6 The term User is defined in Rule 1.5(ee) as “any Member or Sponsored Participant who is authorized to obtain access to the System pursuant to Rule 11.3.”

    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.7

    7See Nasdaq Rule 4756(b), which permits Nasdaq Market Makers and Nasdaq ECNs to attribute their quotations on Nasdaq. See also Nasdaq Rule 4702(b)(2)(A), which limits the availability of Nasdaq “Price to Display Orders” to Nasdaq Market Makers and further states that all Price to Display Orders are Attributable Orders.

    2. Statutory Basis

    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.8 In particular, the proposal is consistent with Section 6(b)(5) of the Act 9 because it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in facilitating transactions in securities, to remove impediments to, and perfect the mechanism of, a free and open market and a national market system and, in general, to protect investors and the public interest.

    8 15 U.S.C. 78f(b).

    9 15 U.S.C. 78f(b)(5).

    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.10

    10See supra note 7.

    (B) Self-Regulatory Organization's Statement on Burden on Competition

    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.11

    11Id.

    (C) Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants or Others

    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.

    III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action

    The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act 12 and Rule 19b-4(f)(6) thereunder.13 Because the proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act and Rule 19b-4(f)(6) thereunder.14

    12 15 U.S.C. 78s(b)(3)(A)(iii).

    13 17 CFR 240.19b-4(f)(6).

    14 In addition, Rule 19b-4(f)(6)(iii) requires the Exchange to give the Commission written notice of the Exchange's intent to file the proposed rule change, along with a brief description and text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission. The Exchange has satisfied this requirement.

    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.15 The Commission hereby grants the Exchange's request and designates the proposal operative upon filing.

    15 For purposes only of waiving the 30-day operative delay, the Commission has also considered the proposed rule's impact on efficiency, competition, and capital formation. See 15 U.S.C. 78c(f).

    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.

    IV. Solicitation of Comments

    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:

    Electronic Comments

    • Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or

    • Send an email to [email protected]. Please include File No. SR-EDGX-2016-01 on the subject line.

    Paper Comments

    • Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.

    All submissions should refer to File No. SR-EDGX-2016-01. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549, on official business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of such filing will also be available for inspection and copying at the principal office of the Exchange. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File No. SR-EDGX-2016-01 and should be submitted on or before February 29, 2016.

    16 17 CFR 200.30-3(a)(12).

    For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.16

    Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02336 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION Proposed Collection; Comment Request Upon Written Request, Copies Available From: Securities and Exchange Commission, Office of FOIA Services, 100 F Street NE., Washington, DC 20549-2736. Extension: Rule 605 of Regulation NMS; SEC File No 270-488, OMB Control No. 3235-0542

    Notice is hereby given that pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.) (“PRA”), the Securities and Exchange Commission (“Commission”) is soliciting comments on the existing collection of information provided for in Rule 605 of Regulation NMS (“Rule 605”) (17 CFR 242.605),1 under the Securities Exchange Act of 1934 (15 U.S.C. 78a, et seq.) (“Exchange Act”). The Commission plans to submit this existing collection of information to the Office of Management and Budget (“OMB”) for extension and approval. Rule 605, formerly known as, Rule 11Ac1-5, requires market centers to make available to the public monthly order execution reports in electronic form. The Commission believes that many market centers retain most, if not all, of the underlying raw data necessary to generate these reports in electronic format. Once the necessary data is collected, market centers could either program their systems to generate the statistics and reports, or transfer the data to a service provider (such as an independent company in the business of preparing such reports or a self-regulatory organization) that would generate the statistics and reports.

    1 Regulation NMS, adopted by the Commission in June 2005, redesignated the national market system rules previously adopted under Section 11A of the Exchange Act. Rule 11Ac1-5 under the Exchange Act was redesignated Rule 605 of Regulation NMS. No substantive amendments were made to Rule 605 of Regulation NMS. See Securities Exchange Act Release No. 51808 (June 9, 2005), 70 FR 37496 (June 29, 2005).

    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 Information Officer, Securities and Exchange Commission, c/o Remi Pavlik-Simon, 100 F Street NE., Washington, DC 20549, or send an email to: [email protected].

    Dated: February 2, 2016. Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02337 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION [Release No. 34-77015; File No. SR-FINRA-2016-003] 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 February 2, 2016.

    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)1 and Rule 19b-4 thereunder,2 notice is hereby given that on January 27, 2016, Financial Industry Regulatory Authority, Inc. (“FINRA”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change as described in Items I and II below, which Items have been prepared by FINRA. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.

    1 15 U.S.C. 78s(b)(1).

    2 17 CFR 240.19b-4.

    I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change

    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 http://www.finra.org, at the principal office of FINRA and at the Commission's Public Reference Room.

    II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change

    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.

    A. Self-Regulatory Organization's Statement of the Purpose of, and the Statutory Basis for, the Proposed Rule Change 1. Purpose

    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”).3 Rule 6730 sets forth the requirements that apply to firms when reporting transactions in TRACE-eligible securities,4 and provides the specific items of information that must be included in a TRACE trade report. Among other things, Rules 6730(c) and (d) require that firms report the commission (total dollar amount) separately on the TRACE trade report for agency transactions. FINRA then combines the dollar amount that is reported as the commission with the amount that is reported in the price field, and disseminates to the market this aggregate amount as the transaction's price. For principal transactions, Rule 6730(d)(1) provides that firms must report a price that includes the mark-up/mark-down, and FINRA disseminates this price to the market.

    3See Securities Exchange Act Release No. 75588 (August 3, 2015), 80 FR 47546 (August 7, 2015) (Notice of Filing of File No. SR-FINRA-2015-026).

    4 Rule 6710 generally defines a “TRACE-eligible security” as: (1) a debt security that is U.S. dollar-denominated and issued by a U.S. or foreign private issuer (and, if a “restricted security” as defined in Securities Act Rule 144(a)(3), sold pursuant to Securities Act Rule 144A); or (2) a debt security that is U.S. dollar denominated and issued or guaranteed by an “Agency” as defined in Rule 6710(k) or a “Government-Sponsored Enterprise” as defined in Rule 6710(n).

    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, 2015.5 In its filing, FINRA represented that the implementation date of these amendments would be May 23, 2016. FINRA has since determined to extend the implementation date for this proposal to July 18, 2016 to provide members additional time to complete systems changes necessary to comply with SR-FINRA-2015-026.

    5See Securities Exchange Act Release No. 76176 (October 16, 2015), 80 FR 64039 (October 22, 2015) (Order Approving File No. SR-FINRA-2015-026).

    FINRA has filed the proposed rule change for immediate effectiveness.

    2. Statutory Basis

    FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,6 which requires, among other things, that FINRA rules must be designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, and, in general, to protect investors and the public interest, and Section 15A(b)(9) of the Act,7 which requires that FINRA rules not impose any burden on competition that is not necessary or appropriate.

    6 15 U.S.C. 78o-3(b)(6).

    7 15 U.S.C. 78o-3(b)(9).

    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.

    B. Self-Regulatory Organization's Statement on Burden on Competition

    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.

    C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others

    Written comments were neither solicited nor received.

    III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action

    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 8 and Rule 19b-4(f)(6) thereunder.9

    8 15 U.S.C. 78s(b)(3)(A).

    9 17 CFR 240.19b-4(f)(6). In addition, Rule 19b-4(f)(6)(iii) requires a self-regulatory organization to give the Commission written notice of its intent to file the proposed rule change, along with a brief description and text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission. FINRA has satisfied this requirement.

    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.

    IV. Solicitation of Comments

    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:

    Electronic Comments

    • Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or

    • Send an email to [email protected]. Please include File Number SR-FINRA-2016-003 on the subject line.

    Paper Comments

    • Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.

    All submissions should refer to File Number SR-FINRA-2016-003. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549 on official business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of such filing also will be available for inspection and copying at the principal office of FINRA. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-FINRA-2016-003, and should be submitted on or before February 29, 2016.

    10 17 CFR 200.30-3(a)(12).

    For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.10

    Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02331 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION [Release No. 34-77035; File No. SR-MIAX-2016-02] Self-Regulatory Organizations; Miami International Securities Exchange LLC; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend Exchange Rule 301 February 2, 2016.

    Pursuant to the provisions of Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”) 1 and Rule 19b-4 thereunder,2 notice is hereby given that on January 20, 2016, Miami International Securities Exchange LLC (“MIAX” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”) a proposed rule change as described in Items I and II below, which Items have been prepared by the Exchange. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.

    1 15 U.S.C. 78s(b)(1).

    2 17 CFR 240.19b-4.

    I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change

    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 http://www.miaxoptions.com/filter/wotitle/rule_filing, at MIAX's principal office, and at the Commission's Public Reference Room.

    II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change

    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.

    A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose

    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 3 from splitting orders into multiple smaller orders for any purpose other than best execution.

    3 The term “Member” means an individual or organization approved to exercise trading rights associated with a Trading Permit. Members are deemed “members” under the Exchange Act. See Exchange Rule 100.

    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 used by the Exchange.4 Finally, the Exchange believes that the unbundling of orders generally serves no purpose to the customer that entered the order and may cause unnecessary delays in the execution of said orders.

    4 For example, pursuant to Exchange Rule 514(g)(2), small size orders, or orders of five contracts or less, are allocated to the Primary Lead Market Maker (“PLMM”) if the PLMM has a priority quote at the NBBO. If a Member was to break up a large order into several smaller orders of five contracts or less, the PLMM could unfairly garner a greater trade allocation than it was otherwise entitled to.

    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.5 The Exchange notes further that other US options exchanges have rules prohibiting the unbundling of orders for a variety of reasons, including the early termination of any price improvement mechanism auction conducted by an exchange, and violations of these rules may be considered conduct inconsistent with just and equitable principles of trade.6

    5 Specifically, it shall be considered conduct inconsistent with just and equitable principles of trade, in accordance with Rule 301, for any Member to enter orders, quotes, Agency Orders, or other responses for the purpose of disrupting or manipulating the Auction. Such conduct includes, but is not limited to, engaging in a pattern or practice of submitting unrelated orders that cause an Auction to conclude before the end of the RFR period and engaging in a pattern of conduct where the Member submitting the Agency Order into the PRIME breaks up the Agency Order into separate orders for two (2) or fewer contracts for the purpose of gaining a higher allocation percentage than the Member would have otherwise received in accordance with the allocation procedures contained in paragraph (a)(2)(iii) or (b)(2)(iii) above. See Exchange Rule 515A, Interpretations and Policies .01.

    6See Securities Exchange Act Release Nos. 62667 (August 9, 2010), 75 FR 50013 (August 16, 2010) (SR-NYSEAmex-2010-77) (adopting NYSE Amex Rule 995NY(d)); and 52872 (December 1, 2005), 70 FR 73043 (December 8, 2005), (SR-CBOE-2005-92) (adopting CBOE Rule 4.23). See also International Securities Exchange LLC Rule 723 Supplementary Material .01 (prohibiting the entering of orders, quotes, Agency Orders, Counter-Side Orders or Improvement Orders for the purpose of disrupting or manipulating the Price Improvement Mechanism Auction), CBOE Rule 6.74A Interpretations and Policies .02 (prohibiting the submission of unrelated orders that cause an Automated Improvement Mechanism Auction to conclude before the end of the RFR period) and NASDAQ OMX PHLX LLC Rule 1080(b)(iii).

    2. Statutory Basis

    MIAX believes that its proposed rule change is consistent with Section 6(b) of the Act 7 in general, and furthers the objectives of Section 6(b)(5) of the Act 8 in particular, in that it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in facilitating transactions in securities, to remove impediments to and perfect the mechanisms of a free and open market and a national market system and, in general, to protect investors and the public interest.

    7 15 U.S.C. 78f(b).

    8 15 U.S.C. 78f(b)(5).

    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.

    B. Self-Regulatory Organization's Statement on Burden on Competition

    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.

    C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others

    Written comments were neither solicited nor received.

    III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action

    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 9 and Rule 19b-4(f)(6) 10 thereunder.

    9 15 U.S.C. 78s(b)(3)(A).

    10 17 CFR 240.19b-4(f)(6). As required under Rule 19b-4(f)(6)(iii), the Exchange provided the Commission with written notice of its intent to file the proposed rule change, along with a brief description and the text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission.

    A proposed rule change filed pursuant to Rule 19b-4(f)(6) under the Act 11 normally does not become operative for 30 days after the date of its filing. However, Rule 19b-4(f)(6)(iii) 12 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. The Exchange states that waiver of the operative delay would enable market participants to benefit from the proposed language codifying existing Exchange procedures when dealing with the unlawful unbundling of orders and would help to prevent this distortive practice. For this reason, the Commission believes that waiver of the 30-day operative delay is consistent with the protection of investors and the public interest. Therefore, the Commission hereby waives the operative delay and designates the proposed rule change operative upon filing.13

    11 17 CFR 240.19b-4(f)(6).

    12 17 CFR 240.19b-4(f)(6)(iii).

    13 For purposes only of waiving the 30-day operative delay, the Commission has considered the proposed rule's impact on efficiency, competition, and capital formation. See 15 U.S.C. 78c(f).

    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.

    IV. Solicitation of Comments

    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:

    Electronic Comments

    • Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or

    • Send an email to [email protected]. Please include File Number SR-MIAX-2016-02 on the subject line.

    Paper Comments

    • Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.

    All submissions should refer to File Number SR-MIAX-2016-02. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549, on official business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-MIAX-2016-02 and should be submitted on or before February 29, 2016.

    For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.14

    Robert W. Errett, Deputy Secretary.

    14 17 CFR 200.30-3(a)(12).

    [FR Doc. 2016-02335 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION [Release No. 34-77033; File No. SR-BATS-2016-12] 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 February 2, 2016.

    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),1 and Rule 19b-4 thereunder,2 notice is hereby given that on January 28, 2016, BATS Exchange, Inc. (“Exchange” or “BATS”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change as described in Items I and II below, which Items have been prepared by the Exchange. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.

    1 15 U.S.C. 78s(b)(1).

    2 17 CFR 240.19b-4.

    I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change

    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.3

    3 17 CFR 240.19b-4(f)(6)(iii).

    The text of the proposed rule change is available at the Exchange's Web site at www.batstrading.com, at the principal office of the Exchange, and at the Commission's Public Reference Room.

    II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change

    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.

    A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose Background

    On August 30, 2011, the Exchange received approval of rules applicable to the qualification, listing and delisting of securities of issuers on the Exchange.4 More recently, the Exchange received approval to operate a pilot program that is designed to incentivize certain Market Makers 5 registered with the Exchange as ETP CLPs, as defined in Interpretation and Policy .03 to Rule 11.8, to enhance liquidity on the Exchange in certain ETPs 6 listed on the Exchange and thereby qualify to receive part of a daily rebate as part of the Program under Interpretation and Policy .03 to Rule 11.8.7

    4See Securities Exchange Act Release No. 65225 (August 30, 2011), 76 FR 55148 (September 6, 2011) (SR-BATS-2011-018).

    5 As defined in BATS Rules, the term “Market Maker” means a Member that acts a as a market maker pursuant to Chapter XI of BATS Rules.

    6 ETP is defined in Interpretation and Policy .03(b)(4) to Rule 11.8.

    7See Securities Exchange Act Release No. 72692 (July 28, 2014), 79 FR 44908 (August 1, 2014) (SR-BATS-2014-022) (“CLP Approval Order”).

    The Program was approved by the Commission on a pilot basis running one-year from the date of implementation.8 The Commission approved the Program on July 28, 2014.9 The Exchange implemented the Program on July 28, 2014 and the pilot period for the Program was originally scheduled to end on July 28, 2015 until it was extended to end on October 28, 2015 10 and later extended to January 28, 2016.11

    8See id at 44909.

    9Id.

    10See Securities Exchange Act Release No. 75518 (July 24, 2015), 80 FR 45566 (July 30, 2015 (SR-BATS-2015-55).

    11See Securities Exchange Act Release No. 76293 (October 28, 2015), 80 FR 67808 (November 3, 2015 (SR-BATS-2015-96).

    Proposal To Extend the Operation of the Program

    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.

    2. Statutory Basis

    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.12 In particular, the Exchange believes the proposed change furthers the objectives of Section 6(b)(5) of the Act,13 in that it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in facilitating transactions in securities, and to remove impediments to and perfect the mechanism of a free and open market and a national market system. The Exchange believes that extending the pilot period for the Program is consistent with these principles because the Program is reasonably designed to enhance quote competition, improve liquidity in securities listed on the Exchange, support the quality of price discovery, promote market transparency, and increase competition for listings and trade executions, while reducing spreads and transaction costs in such securities. Maintaining and increasing liquidity in Exchange-listed securities will help raise investors' confidence in the fairness of the market and their transactions. The extension of the pilot period will allow Exchange [sic] to continue to operate the Program while its proposal to make the Program permanent is under consideration by the Commission.

    12 15 U.S.C. 78f(b).

    13 15 U.S.C. 78f(b)(5).

    B. Self-Regulatory Organization's Statement on Burden on Competition

    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 14 and NYSE Arca Equities, Inc.15

    14See Securities Exchange Act Release No. 69195 (March 20, 2013), 78 FR 18393 (March 26, 2013) (SR-NASDAQ-2012-137).

    15See Securities Exchange Act Release No. 69335 (April 5, 2013), 78 FR 35340 (June 12, 2013) (SR-NYSEARCA-2013-34).

    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.

    C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants or Others

    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.

    III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action

    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 16 and Rule 19b-4(f)(6) thereunder.17

    16 15 U.S.C. 78s(b)(3)(A).

    17 17 CFR 240.19b-4(f)(6). In addition, Rule 19b-4(f)(6) requires a self-regulatory organization to give the Commission written notice of its intent to file the proposed rule change at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission. The Exchange has satisfied this requirement.

    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),18 the Commission may designate a shorter time if such action is consistent with the protection of investors and the public interest.

    18 17 CFR 240.19b-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.19

    19 For purposes only of waiving the operative delay for this proposal, the Commission has considered the proposed rule's impact on efficiency, competition, and capital formation. See 15 U.S.C. 78c(f).

    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.

    IV. Solicitation of Comments

    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:

    Electronic Comments

    • Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or

    • Send an email to [email protected]. Please include File No. SR-BATS-2016-12 on the subject line.

    Paper Comments

    • Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.

    All submissions should refer to File No. SR-BATS-2016-12. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549, on official business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of such filing will also be available for inspection and copying at the principal office of the Exchange. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File No. SR-BATS-2016-12 and should be submitted on or before February 29, 2016.

    For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.20

    Robert W. Errett, Deputy Secretary.

    20 17 CFR 200.30-3(a)(12).

    [FR Doc. 2016-02333 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION [Release No. 34-77032; File No. SR-Phlx-2016-04] Self-Regulatory Organizations; NASDAQ OMX PHLX LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Options Regulatory Fee February 2, 2016.

    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”) 1 , and Rule 19b-4 thereunder,2 notice is hereby given that on January 20, 2016, NASDAQ OMX PHLX LLC (“Phlx” or “Exchange”) filed with the Securities and Exchange Commission (“SEC” or “Commission”) the proposed rule change as described in Items I, II, and III, below, which Items have been prepared by the Exchange. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.

    1 15 U.S.C. 78s(b)(1).

    2 17 CFR 240.19b-4.

    I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change

    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 http://nasdaqomxphlx.cchwallstreet.com/, at the principal office of the Exchange, and at the Commission's Public Reference Room.

    II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change

    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.

    A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose

    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.3

    3 The Exchange notes that it previously filed a rule change to amend the ORF as of February 1, 2016 to $0.0040. This rule change supersedes that filing. See Securities Exchange Act Release No. 75749 (August 21, 2015), 80 FR 52073 (August 27, 2015) (SR-Phlx-2015-71).

    Background

    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 (i.e., that clear in the Customer account of the member's clearing firm at OCC). The Exchange monitors the amount of revenue collected from the ORF to ensure that it, in combination with other regulatory fees and fines, does not exceed regulatory costs. The ORF is imposed upon all transactions executed by a member, even if such transactions do not take place on the Exchange.4 The ORF also includes options transactions that are not executed by an Exchange member but are ultimately cleared by an Exchange member.5 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. The dues and fees paid by members go into the general funds of the Exchange, a portion of which is used to help pay the costs of regulation. The ORF is collected indirectly from members through their clearing firms by OCC on behalf of the Exchange.

    4 The ORF applies to all “C” account origin code orders executed by a member on the Exchange. Exchange Rules require each member to record the appropriate account origin code on all orders at the time of entry in order to allow the Exchange to properly prioritize and route orders and assess transaction fees pursuant to the Rules of the Exchange and report resulting transactions to OCC. See Exchange Rule 1063, Responsibilities of Floor Brokers, and Options Floor Procedure Advice F-4, Orders Executed as Spreads, Straddles, Combinations or Synthetics and Other Order Ticket Marking Requirements. The Exchange represents that it has surveillances in place to verify that members mark orders with the correct account origin code.

    5 In the case where one member both executes a transaction and clears the transaction, the ORF is assessed to the member only once on the execution. In the case where one member executes a transaction and a different member clears the transaction, the ORF is assessed only to the member who executes the transaction and is not assessed to the member who clears the transaction. In the case where a non-member executes a transaction and a member clears the transaction, the ORF is assessed to the member who clears the transaction.

    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.

    ORF Adjustments

    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.6

    6See Options Trader Alert #2015-37.

    2. Statutory Basis

    The Exchange believes that its proposal is consistent with Section 6(b) of the Act 7 in general, and furthers the objectives of Sections 6(b)(4) and 6(b)(5) of the Act 8 in particular, in that it provides for the equitable allocation of reasonable dues, fees and other charges among members and issuers and other persons using any facility or system which the Exchange operates or controls, and is not designed to permit unfair discrimination between customers, issuers, brokers, or dealers.

    7 15 U.S.C. 78f(b).

    8 15 U.S.C. 78f(b)(4) and (5).

    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.9 Additionally, the dues and fees paid by members go into the general funds of the Exchange, a portion of which is used to help pay the costs of regulation. The Exchange believes that the proposed ORF is a small cost for Customer executions.10 The Exchange has in place a regulatory structure to surveil for, exam [sic] and monitor the marketplace for violations of Exchange Rules. The ORF assists the Exchange to fund the cost of this regulation of the marketplace.

    9 The ORF is not charged for orders that clear in categories other than the Customer range at OCC (e.g., Market Maker orders) because members incur the costs of memberships and through their memberships are charged transaction fees, dues and other fees that go into the general funds of the Exchange, a portion of which is used to help pay the costs of regulation.

    10 The Exchange does not assess a Customer any transaction fees in Multiply Listed Options, except in SPY, and pays Customer rebates.

    B. Self-Regulatory Organization's Statement on Burden on Competition

    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, a portion of which is used to help pay the costs of regulation. The Exchange's members are subject to ORF on other options markets.11

    11 The following options exchanges assess an ORF, Chicago Board Options Exchange, Incorporated (“CBOE”), C2 Options Exchange, Inc. (“C2”), the International Securities Exchange, LLC (“ISE”), NYSE Arca, Inc. (“NYSEArca”) and [sic] NYSE AMEX LLC (“NYSEAmex”), BATS Exchange, Inc. (“BATS”) and The NASDAQ Options Market LLC (“NOM”).

    C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others

    No written comments were either solicited or received.

    III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action

    The foregoing rule change has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act.12

    12 15 U.S.C. 78s(b)(3)(A)(ii).

    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.

    IV. Solicitation of Comments

    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:

    Electronic Comments

    • Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or

    • Send an email to [email protected]. Please include File Number SR-Phlx-2016-04 on the subject line.

    Paper Comments

    • Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.

    All submissions should refer to File Number SR-Phlx-2016-04. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549, on official business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-Phlx-2016-04 and should be submitted on or before February 29, 2016.

    For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.13

    13 17 CFR 200.30-3(a)(12).

    Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02332 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION Sunshine Act Meeting

    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 de minimis counting requirements to security-based swap transactions connected with a non-U.S. person's dealing activity that are arranged, negotiated, or executed by personnel located in a U.S. branch or office or by personnel of an agent of such non-U.S. person located in a U.S. branch or office.

    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.

    Dated: February 3, 2016. Brent J. Fields, Secretary.
    [FR Doc. 2016-02490 Filed 2-4-16; 11:15 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION [Release No. 34-77034; File No. SR-MIAX-2016-03] 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 February 2, 2016.

    Pursuant to the provisions of Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”) 1 and Rule 19b-4 thereunder,2 notice is hereby given that on January 20, 2016, Miami International Securities Exchange LLC (“MIAX” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”) a proposed rule change as described in Items I and II below, which Items have been prepared by the Exchange. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.

    1 15 U.S.C. 78s(b)(1).

    2 17 CFR 240.19b-4.

    I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change

    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 http://www.miaxoptions.com/filter/wotitle/rule_filing, at MIAX's principal office, and at the Commission's Public Reference Room.

    II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change

    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.

    A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose

    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”),3 orders that are not executed during the opening on the Exchange are handled.

    3 A Do Not Route or “DNR” order is an order that will never be routed outside of the Exchange regardless of the prices displayed by away markets. A DNR order may execute on the Exchange at a price equal to or better than, but not inferior to, the best away market price but, if that best away market remains, the DNR order will be handled in accordance with the managed interest process described in Rule 515(c)(1)(ii). See Exchange Rule 516(g).

    First, the Exchange proposes to amend Rule 503(f), Opening Process, to clarify the process that occurs when (i) the MIAX System 4 has completed the opening imbalance process and there are unexecuted contracts remaining following an opening transaction, or (ii) if there is no opening transaction and the Exchange 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 current Rule 503(f)(1).5 In the latter situation, non-routable orders then in the System that cross the Away Best Bid or Offer (“ABBO”) will be cancelled and are not included in the Managed Interest Process, as described in proposed Rule 515(c)(1)(ii)(B).

    4 The term “System” means the automated trading system used by the Exchange for the trading of securities. See Exchange Rule 100.

    5 If there are no quotes or orders that lock or cross each other, the System will open by disseminating the Exchange's best bid and offer among quotes and orders that exist in the System at that time. See Exchange Rule 503(f)(1).

    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.

    DNR Orders at the Opening

    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.6 If the System opens with an opening transaction after conducting the Imbalance Process as set forth in Exchange Rule 503(f)(2)(vii), 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 the remaining size will be automatically submitted as a new order.7

    6See Exchange Rule 503(f)(2)(vii)(B).

    7Id.

    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,8 non-routable orders then in the System that cross the ABBO will be cancelled and therefore, because they are cancelled, are not included in the Managed Interest Process.

    8See supra note 5.

    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 515.9 Specifically, such orders are submitted into the Managed Interest Process, as described below, except when the Exchange opens by disseminating quotations rather than executing contracts. In this limited circumstance, non-routable orders (DNR Orders) that cross the ABBO are not submitted to the Managed Interest Process, and instead are cancelled.

    9 The System will execute orders at the opening that have contingencies and nonroutable orders, such as a “Do Not Route” or “DNR” Orders to the extent possible. DNR orders together with other nonroutable orders will be handled after the opening in accordance with Rule 515. See Exchange Rule 503(f)(2)(vii)(B)(6).

    Managed Interest Process

    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.10

    10See Exchange Rule 515(c)(1)(ii).

    The Proposal

    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 the remaining size will be automatically submitted as a new order.

    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 (i.e., the ability to ascertain the current prices on all markets) following the opening. Such participants are able then to determine whether to re-submit their orders (with or without a DNR designation) and whether to establish a different limit price based on then-current market conditions. The Exchange believes that the precise description of this existing functionality should be included in the Exchange's rules in order to inform participants that submit non-routable orders that there are additional opportunities to re-determine and possibly modify the routing status and limit price of their orders. The proposed rule change should assist participants in making decisions concerning such opportunities by clarifying the relationship between the Exchange's Opening Process and when non-routable orders not executed when the Exchange opens by disseminating its best bid and offer are not included in the Managed Interest Process.

    2. Statutory Basis

    MIAX believes that its proposed rule change is consistent with Section 6(b) of the Act 11 in general, and furthers the objectives of Section 6(b)(5) of the Act 12 in particular, in that it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in facilitating transactions in securities, to remove impediments to and perfect the mechanisms of a free and open market and a national market system and, in general, to protect investors and the public interest.

    11 15 U.S.C. 78f(b).

    12 15 U.S.C. 78f(b)(5).

    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.

    B. Self-Regulatory Organization's Statement on Burden on Competition

    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.

    C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others

    Written comments were neither solicited nor received.

    III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action

    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 13 and Rule 19b-4(f)(6) 14 thereunder.

    13 15 U.S.C. 78s(b)(3)(A).

    14 17 CFR 240.19b-4(f)(6). As required under Rule 19b-4(f)(6)(iii), the Exchange provided the Commission with written notice of its intent to file the proposed rule change, along with a brief description and the text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission.

    A proposed rule change filed pursuant to Rule 19b-4(f)(6) under the Act 15 normally does not become operative for 30 days after the date of its filing. However, Rule 19b-4(f)(6)(iii) 16 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. The Exchange states that waiver of the operative delay would enable market participants to benefit from the clarifying language regarding how the Managed Interest Process operates without undue delay. For this reason, the Commission believes that waiver of the 30-day operative delay is consistent with the protection of investors and the public interest. Therefore, the Commission hereby waives the operative delay and designates the proposed rule change operative upon filing.17

    15 17 CFR 240.19b-4(f)(6).

    16 17 CFR 240.19b-4(f)(6)(iii).

    17 For purposes only of waiving the 30-day operative delay, the Commission has considered the proposed rule's impact on efficiency, competition, and capital formation. See 15 U.S.C. 78c(f).

    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.

    IV. Solicitation of Comments

    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:

    Electronic Comments

    • Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or

    • Send an email to [email protected]. Please include File Number SR-MIAX-2016-03 on the subject line.

    Paper Comments

    • Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.

    All submissions should refer to File Number SR-MIAX-2016-03. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549, on official business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-MIAX-2016-03 and should be submitted on or before February 29, 2016.

    For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.18

    18 17 CFR 200.30-3(a)(12).

    Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02334 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION Proposed Collection; Comment Request Upon Written Request Copies Available From: Securities and Exchange Commission, Office of FOIA Services, 100 F Street NE., Washington, DC 20549-0213. Extension: Form F-7. SEC File No. 270-331, OMB Control No. 3235-0383.

    Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.), the Securities and Exchange Commission (“Commission”) is soliciting comments on the collection of information summarized below. The Commission plans to submit this existing collection of information to the Office of Management and Budget for extension and approval.

    Form F-7 (17 CFR 239.37) is a registration statement under the Securities Act of 1933 (15 U.S.C. 77a et seq.) used to register securities that are offered for cash upon the exercise of rights granted to a registrant's existing security holders to purchase or subscribe such securities. The information collected is intended to ensure that the information required to be filed by the Commission permits verification of compliance with securities law requirements and assures the public availability of such information. Form F-7 takes approximately 4 hours per response to prepare and is filed by approximately 5 respondents. We estimate that 25% of 4 hours per response (one hour) is prepared by the company for a total annual reporting burden of 5 hours (one hour per response × 5 responses).

    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: [email protected].

    Dated: February 2, 2016. Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02338 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SECURITIES AND EXCHANGE COMMISSION [Release No. 34-77014; File No. SR-NYSEMKT-2016-16] 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 February 2, 2016.

    Pursuant to Section 19(b)(1) 1 of the Securities Exchange Act of 1934 (the “Act”),2 and Rule 19b-4 thereunder,3 notice is hereby given that on January 27, 2016, NYSE MKT LLC (the “Exchange” or “NYSE MKT”) filed with the Securities and Exchange Commission (the “Commission”) the proposed rule change as described in Items I and II below, which Items have been prepared by the self-regulatory organization. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.

    1 15 U.S.C. 78s(b)(1).

    2 15 U.S.C. 78a.

    3 17 CFR 240.19b-4.

    I. Self-Regulatory Organization's Statement of the Terms of the Substance of the Proposed Rule Change

    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 www.nyse.com, at the principal office of the Exchange, and at the Commission's Public Reference Room.

    II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change

    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.

    A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose

    The Exchange is proposing to amend certain of its rules related to Binary Return Derivatives contracts (“ByRDs”), which the Exchange introduced in 2007.4

    4See Securities Exchange Act Release No. 56251 (August 14, 2007), 72 FR 46523 (August 20, 2007) (SR-Amex-2004-27) (Order approving listing of Fixed Return Options (“FROs”)); see also Securities Exchange Act Release No. 71957 (April 16, 2014), 79 FR 22563 (April 22, 2014) (SR-NYSEMKT-2014-06) (Order approving name change from FROs to Binary Return Derivatives (ByRDs) and re-launch of these products, with certain modification, and amending Obvious Errors rules to include ByRDs). ByRDs are European-style option contracts on individual stocks, exchange-traded funds (“ETFs”) and Index-Linked Securities that have a fixed return in cash based on a set strike price; satisfy specified listing criteria; and may only be exercised at expiration pursuant to the Rules of the Options Clearing Corporation (the “OCC”).

    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.5 The current ByRDs rules are silent regarding the treatment of ByRDs during trading halts and suspensions of options contracts. The Exchange therefore believes that the proposed change would add clarity and transparency to Exchange rules and 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.

    5See proposed Rule 953ByRDs (Trading Halts and Suspensions of Binary Return Derivatives).

    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.” 6 The Exchange proposes to revise this rule to include instances when an Exchange holiday falls on a Thursday. Specifically, as revised, new series would be added for trading “on Thursday each week, unless Thursday or Friday is an Exchange holiday in which case new expiration series would be added for trading on Wednesday.” 7 The Exchange notes that this proposed change 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 benefit market participants.

    6See Rule 903ByRDs(b).

    7See proposed Rule 903ByRDs (b) (“Consecutive Week Expiration Series: The Exchange will list Binary Return Derivatives having five (5) consecutive weekly expiration series available at one time. Each expiration series will expire at the end of the week, normally a Friday, with consecutive week expirations covering the next five (5) calendar weeks. New expiration week series will be added for trading on Thursday each week, unless Thursday or 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.” 8 Thus, as proposed, the transaction would only be adjusted to $1.02 if the adjustment would result in a price greater than $1.02. As ByRDs will either pay $0 or $100 at expiration, a single ByRDs contract should not have a value greater than $1.00, therefore the Exchange believes that any adjustment under the provisions of the Catastrophic Error rule should be capped at a price no higher than $1.02. Capping the adjustment price at $1.02 for Catastrophic Errors involving ByRDs options is consistent with the adjustment process for obvious errors involving ByRDs option, which are also capped at $1.02.9 Similarly, to ensure consistency in Exchange rules, the Exchange propose to strike from the definition of Catastrophic Error rules, the clause that states “except for Binary Return Derivatives where any transaction occurring at a price greater than $1.02 shall qualify as a Catastrophic Error.” 10 The change to paragraph (d)(1) of the Rule would allow transactions in ByRDs to be subject to standard Catastrophic Error rules (i.e., transactions that are higher or lower than the Theoretical Price by $.50 or more shall be deemed a Catastrophic Error). The Exchange notes that, to date, no ByRDs transactions have been deemed Catastrophic Errors and the Exchange did not adjust any ByRDs transaction per current Rule 975NY(d)(3)(A). The proposed change would ensure that ByRDs trades that are deemed Catastrophic Errors are appropriately adjusted.11

    8See proposed Rule 975NY(d)(3)(A).

    9See Rule 975NY(c)(6).

    10See proposed Rule 975NY(d)(1).

    11 The Exchange notes that ByRDs contracts were outside of the scope of the industry wide effort to harmonize Obvious and Catastrophic Error rules, and the proposed change therefore does not impact the harmonization effort. See Securities Exchange Act Release No. 74920 (May 8, 2015), 80 FR 27816, 27822 (May 14, 2015) (SR-NYSEMKT-2015-39).

    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.” 12 The Exchange believes the proposed change would correct an existing typographical error in Exchange rules.

    12See proposed Rule 462(d)(10)(A) (striking the extraneous words “is or a customer”).

    Implementation

    The Exchange proposes to announce the implementation of the proposed rule change via Trader Update.

    2. Statutory Basis

    The Exchange believes the proposed rule change is consistent with Section 6(b) 13 of the Securities Exchange Act of 1934 (the “Act”), in general, and furthers the objectives of Section 6(b)(5),14 in particular, in that it is designed to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in facilitating transactions in securities, and to remove impediments to and perfect the mechanism of a free and open market and a national market system.

    13 15 U.S.C. 78f(b).

    14 15 U.S.C. 78f(b)(5).

    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.

    B. Self-Regulatory Organization's Statement on Burden on Competition

    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.

    C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others

    No written comments were solicited or received with respect to the proposed rule change.

    III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action

    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 15 and Rule 19b-4(f)(6) thereunder.16

    15 15 U.S.C. 78s(b)(3)(A).

    16 17 CFR 240.19b-4(f)(6). As required under Rule 19b-4(f)(6)(iii), the Exchange provided the Commission with written notice of its intent to file the proposed rule change, along with a brief description and the text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change.

    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.

    IV. Solicitation of Comments

    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:

    Electronic Comments

    • Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or

    • Send an email to [email protected]. Please include File Number SR-NYSEMKT-2016-16 on the subject line.

    Paper Comments

    • Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.

    All submissions should refer to File Number SR-NYSEMKT-2016-16. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549 on official business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of such filing also will be available for inspection and copying at the principal office of the Exchange. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-NYSEMKT-2016-16, and should be submitted on or before February 29, 2016.

    17 17 CFR 200.30-3(a)(12).

    For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.17

    Robert W. Errett, Deputy Secretary.
    [FR Doc. 2016-02330 Filed 2-5-16; 8:45 am] BILLING CODE 8011-01-P
    SOCIAL SECURITY ADMINISTRATION [Docket No: SSA-2016-0002] Agency Information Collection Activities: Proposed Request and Comment Request

    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: [email protected].

    (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: [email protected].

    Or you may submit your comments online through www.regulations.gov, referencing Docket ID Number [SSA-2016-0002].

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden (hours)
    MSSICS 801,789 1 20 267,263 MSSICS/Signature Proxy 666,431 1 19 211,036 Paper 135,357 1 20 45,119 Totals 1,603,577 523,418

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden (hours)
    SSA-2574 Paper version 50,000 1 7 5,833 Intranet version (MSSICS) 150,000 1 7 17,500 Totals 200,000 23,333

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden (hours)
    SSA-545 7,000 1 120 14,000

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden (hours)
    SSA-1699 16,000 1 20 5,333

    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 [email protected].

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden (hours)
    SSA-781 14,000 1 10 2,333

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden (hours)
    SSA-4641 (paper) 252,500 1 6 25,250 e4641 and AFI (electronic) 15,747,500 1 2 524,917 Totals 16,000,000 550,167

    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.

    Modality of
  • completion
  • Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden (hours)
    SSA-769-U4 7,483 1 8 998

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden
  • (hours)
  • SSA-770 1,200 1 5 100

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden
  • (hours)
  • Access to Records 10,000 1 11 1,833 Designating a Representative for Disclosure of Records 3,000 1 2 6,000 Amendment of Records 100 1 10 17 Consent of Release of Records 3,000,000 1 3 150,000 FOIA Requests for Records 15,000 1 5 1,250 Waiver/Reduction of Fees 400 1 5 33 Respondents who request access to an extract of their SSN record 10 1 8.5 1 Totals 3,028,510 159,134

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden
  • (hours)
  • SSA-322 1,000 1 15 250

    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.

    Modality of completion Number of
  • responses
  • Frequency of response Average
  • burden per
  • response
  • (minutes)
  • Estimated total annual burden
  • (hours)
  • SSA-1199-(Country) 12,500 1 5 1,041
    Dated: February 3, 2016. Naomi R. Sipple, Reports Clearance Officer, Social Security Administration.
    [FR Doc. 2016-02353 Filed 2-5-16; 8:45 am] BILLING CODE 4191-02-P
    DEPARTMENT OF STATE [Public Notice: 9437] 60-Day Notice of Proposed Information Collection: Overseas Schools Grant Status Report ACTION:

    Notice of request for public comment.

    SUMMARY:

    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.

    DATES:

    The Department will accept comments from the public up to April 8, 2016.

    ADDRESSES:

    You may submit comments by any of the following methods:

    Web: Persons with access to the Internet may comment on this notice by going to www.Regulations.gov. You can search for the document by entering “Docket Number: DOS-2015-0066” in the Search field. Then click the “Comment Now” button and complete the comment form.

    Email: [email protected].

    Regular Mail: Send written comments to: Office of Overseas Schools, U.S. Department of State, 2201 C Street NW., Washington, DC 20520.

    Fax: 202-261-8224

    Hand Delivery or Courier: same as mail address.

    You must include the DS form number, information collection title, and the OMB control number in any correspondence.
    FOR FURTHER INFORMATION CONTACT:

    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 [email protected].

    SUPPLEMENTARY INFORMATION:

    Title of Information Collection: Overseas Schools Grant Status Report.

    OMB Control Number: 1405-0033.

    Type of Request: Extension of a Currently Approved Collection.

    Originating Office: Bureau of Administration, A/OPR/OS.

    Form Number: DS-2028.

    Respondents: Overseas schools grantees.

    Estimated Number of Respondents: 195.

    Estimated Number of Responses: 195.

    Average Time per Response: 15 minutes.

    Total Estimated Burden Time: 49 hours.

    Frequency: Annually.

    Obligation to Respond: Required to Obtain or Retain a Benefit.

    We are soliciting public comments to permit the Department to:

    • Evaluate whether the proposed information collection is necessary for the proper functions of the Department.

    • Evaluate the accuracy of our estimate of the time and cost burden for this proposed collection, including the validity of the methodology and assumptions used.

    • Enhance the quality, utility, and clarity of the information to be collected.

    • Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.

    Please note that comments submitted in response to this Notice are public record. Before including any detailed personal information, you should be aware that your comments as submitted, including your personal information, will be available for public review.

    Abstract of proposed collection: The Office of Overseas Schools of the Department of State (A/OPR/OS) is responsible for determining that adequate educational opportunities exist at Foreign Service Posts for dependents of U.S. Government personnel stationed abroad, and for assisting American-sponsored overseas schools to demonstrate U.S. educational philosophy and practice. The information gathered provides the technical and professional staff of A/OPR/OS the means by which obligations, expenditures and reimbursements of the grant funds are monitored to ensure the grantee is in compliance with the terms of the grant.

    Methodology: Information is collected via electronic and paper submission.

    Dated: November 13, 2015. Janice DeGarmo, Acting Executive Director, Bureau of Administration, Department of State.
    [FR Doc. 2016-02471 Filed 2-5-16; 8:45 am] BILLING CODE 4710-24-P
    DEPARTMENT OF TRANSPORTATION Federal Aviation Administration [Summary Notice No. PE-2016-13] Petition for Exemption; Summary of Petition Received; Firestorm UAV AGENCY:

    Federal Aviation Administration (FAA), DOT.

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    Comments on this petition must identify the petition docket number and must be received on or February 29, 2016.

    ADDRESSES:

    Send comments identified by docket number FAA-2015-0931 using any of the following methods:

    Federal eRulemaking Portal: Go to http://www.regulations.gov and follow the online instructions for sending your comments electronically.

    Mail: Send comments to Docket Operations, M-30; U.S. Department of Transportation (DOT), 1200 New Jersey Avenue SE., Room W12-140, West Building Ground Floor, Washington, DC 20590-0001.

    Hand Delivery or Courier: Take comments to Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.

    Fax: Fax comments to Docket Operations at 202-493-2251.

    Privacy: In accordance with 5 U.S.C. 553(c), DOT solicits comments from the public to better inform its rulemaking process. DOT posts these comments, without edit, including any personal information the commenter provides, to http://www.regulations.gov, as described in the system of records notice (DOT/ALL-14 FDMS), which can be reviewed at http://www.dot.gov/privacy.

    Docket: Background documents or comments received may be read athttp://www.regulations.gov at any time. Follow the online instructions for accessing the docket or go to the Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.

    FOR FURTHER INFORMATION CONTACT:

    Dan Ngo, 202-267-4264, 800 Independence Avenue SW., Washington, DC 20591.

    This notice is published pursuant to 14 CFR 11.85.

    Issued in Washington, DC, on January 28, 2016. Lirio Liu, Director, Office of Rulemaking. Petition For Exemption

    Docket No.: FAA-2015-0931.

    Petitioner: Firestorm UAV.

    Section(s) of 14 CFR Affected: part 21; 91.113; 91.119(c); 91.151; 91.209; 91.405(a) and (b); 91.407(a)(1); 91.409(a)(1) and (2); and 91.417(a).

    Description of Relief Sought: Petitioner seeks to operate an unmanned aerial system (UAS) to conduct emergency services operations in nighttime hours.

    [FR Doc. 2016-02345 Filed 2-5-16; 8:45 am] BILLING CODE 4910-13-P
    DEPARTMENT OF TRANSPORTATION Federal Aviation Administration [Summary Notice No. PE-2016-12] Petition for Exemption; Summary of Petition Received; Wes Myers AGENCY:

    Federal Aviation Administration (FAA), DOT.

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    Comments on this petition must identify the petition docket number and must be received on or before February 29, 2016.

    ADDRESSES:

    Send comments identified by docket number FAA-2015-0443 using any of the following methods:

    Federal eRulemaking Portal: Go to http://www.regulations.gov and follow the online instructions for sending your comments electronically.

    Mail: Send comments to Docket Operations, M-30; U.S. Department of Transportation (DOT), 1200 New Jersey Avenue SE., Room W12-140, West Building Ground Floor, Washington, DC 20590-0001.

    Hand Delivery or Courier: Take comments to Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.

    Fax: Fax comments to Docket Operations at 202-493-2251.

    Privacy: In accordance with 5 U.S.C. 553(c), DOT solicits comments from the public to better inform its rulemaking process. DOT posts these comments, without edit, including any personal information the commenter provides, to http://www.regulations.gov, as described in the system of records notice (DOT/ALL-14 FDMS), which can be reviewed at http://www.dot.gov/privacy.

    Docket: Background documents or comments received may be read at http://www.regulations.gov at any time. Follow the online instructions for accessing the docket or go to the Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.

    FOR FURTHER INFORMATION CONTACT:

    Dan Ngo, 202-267-4264, 800 Independence Avenue SW., Washington, DC 20591.

    This notice is published pursuant to 14 CFR 11.85.

    Issued in Washington, DC, on January 28, 2016. Lirio Liu, Director, Office of Rulemaking. Petition for Exemption

    Docket No.: FAA-2015-0443.

    Petitioner: Wes Myers

    Section(s) of 14 CFR Affected: 61.113 (a) & (b).

    Description of Relief Sought: Petitioner seeks to amend Exemption No. 11592A for relief from Condition and Limitation 13 regarding Pilot in Command requirements to operate an unmanned aerial system (UAS) for aerial data collection.

    [FR Doc. 2016-02347 Filed 2-5-16; 8:45 am] BILLING CODE 4910-13-P
    DEPARTMENT OF TRANSPORTATION Federal Motor Carrier Safety Administration [Docket No. FMCSA-2015-0348] Qualification of Drivers; Exemption Applications; Vision AGENCY:

    Federal Motor Carrier Safety Administration (FMCSA), DOT.

    ACTION:

    Notice of applications for exemptions; request for comments.

    SUMMARY:

    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.

    DATES:

    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.

    ADDRESSES:

    You may submit comments bearing the Federal Docket Management System (FDMS) Docket No. FMCSA-2015-0348 using any of the following methods:

    Federal eRulemaking Portal: Go to http://www.regulations.gov. Follow the on-line instructions for submitting comments.

    Mail: Docket Management Facility; U.S. Department of Transportation, 1200 New Jersey Avenue, SE., West Building Ground Floor, Room W12-140, Washington, DC 20590-0001.

    Hand Delivery: West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue, SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal Holidays.

    Fax: 1-202-493-2251.

    Instructions: Each submission must include the Agency name and the docket numbers for this notice. Note that all comments received will be posted without change to http://www.regulations.gov, including any personal information provided. Please see the Privacy Act heading below for further information.

    Docket: For access to the docket to read background documents or comments, go to http://www.regulations.gov at any time or Room W12-140 on the ground level of the West Building, 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The FDMS is available 24 hours each day, 365 days each year. If you want acknowledgment that we received your comments, please include a self-addressed, stamped envelope or postcard or print the acknowledgement page that appears after submitting comments on-line.

    Privacy Act: In accordance with 5 U.S.C. 553(c), DOT solicits comments from the public to better inform its rulemaking process. DOT posts these comments, without edit, including any personal information the commenter provides, to www.regulations.gov, as described in the system of records notice (DOT/ALL-14 FDMS), which can be reviewed at www.dot.gov/privacy.

    FOR FURTHER INFORMATION CONTACT:

    Christine A. Hydock, Chief, Medical Programs Division, (202) 366-4001, [email protected], FMCSA, Department of Transportation, 1200 New Jersey Avenue SE., Room W64-113, Washington, DC 20590-0001. Office hours are 8:30 a.m. to 5 p.m., e.t., Monday through Friday, except Federal holidays. If you have questions regarding viewing or submitting material to the docket, contact Docket Services, telephone (202) 366-9826.

    SUPPLEMENTARY INFORMATION:

    I. Background

    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.

    II. Qualifications of Applicants Lonnie D. Barber

    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 opinion, Mr. Barber's vision is sufficient to perform the driving tasks required to operate a commercial vehicle.”

    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.

    Thomas M. Bowman

    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.

    Daniel T. Brown

    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.

    Samuel S. Byler

    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.

    Robert Fawcett, Jr.

    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.

    James T. Friesner, Jr.

    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.

    Harry J. Glynn

    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.

    Jerry L. Gray

    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.

    Lloyd Hinton

    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.

    James M. Knef

    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.

    Cody McDonnell

    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.

    Brandon J. Michalko

    Mr. Michalko, 25, has a macular hole in his left eye due to a traumatic incident in 2004. The visual acuity in his right eye is 20/20, and in his left eye, 20/200. Following an examination in 2015, his ophthalmologist stated, “In my medical opinion, I believe he does have sufficient vision to perform a driving test required to operate a commercial vehicle.” Mr. Michalko reported that he has driven straight trucks for 8 years, accumulating 416,000 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.

    John L. Ratayczak

    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.

    Dennis C. Rokes

    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.

    Brian W. Roughton

    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.

    Eric A. Simonsen

    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.

    Brian S. Tuttle

    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.

    Steven A. Van Raalte

    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.

    Marvin L. Wernimont

    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.

    Brian J. Yole

    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.

    III. Public Participation and Request for Comments

    FMCSA encourages you to participate by submitting comments and related materials.

    Submitting Comments

    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 http://www.regulations.gov and put the docket number FMCSA-2015-0348 in the “Keyword” box, and click “Search.” When the new screen appears, click on “Comment Now!” button and type your comment into the text box in the following screen. Choose whether you are submitting your comment as an individual or on behalf of a third party and then submit. If you submit your comments by mail or hand delivery, submit them in an unbound format, no larger than 81/2 by 11 inches, suitable for copying and electronic filing. If you submit comments by mail and would like to know that they reached the facility, please enclose a stamped, self-addressed postcard or envelope.

    FMCSA will consider all comments and material received during the comment period and may change this notice based on your comments.

    Viewing Comments and Documents

    To view comments, as well as documents mentioned in this preamble as being available in the docket, go to http://www.regulations.gov and insert the docket number FMCSA-2015-0348 in the “Keyword” box and click “Search.” Next, click “Open Docket Folder” button and choose the document listed to review. If you do not have access to the Internet, you may view the docket online by visiting the Docket Management Facility in Room W12-140 on the ground floor of the DOT West Building, 1200 New Jersey Avenue SE., Washington, DC 20590, between 9 a.m. and 5 p.m., e.t., Monday through Friday, except Federal holidays.

    Issued on: January 21, 2016. Larry W. Minor, Associate Administrator for Policy.
    [FR Doc. 2016-02366 Filed 2-5-16; 8:45 am] BILLING CODE 4910-EX-P
    DEPARTMENT OF TRANSPORTATION Federal Motor Carrier Safety Administration [Docket No. FMCSA-2015-0349] Qualification of Drivers; Exemption Applications; Vision AGENCY:

    Federal Motor Carrier Safety Administration (FMCSA), DOT.

    ACTION:

    Notice of denials.

    SUMMARY:

    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.

    FOR FURTHER INFORMATION CONTACT:

    Christine A. Hydock, Chief, Medical Programs Division, (202) 366-4001, [email protected], FMCSA, Department of Transportation, 1200 New Jersey Avenue SE., Room W64-113, Washington, DC 20590-0001. Office hours are 8:30 a.m. to 5 p.m., e.t., Monday through Friday, except Federal holidays.

    SUPPLEMENTARY INFORMATION:

    Background

    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:

    Allan V. Jorgensen Timothy M. O'Malley James S. Phipps David J. Varricchione

    The following 82 applicants had no experience operating a CMV:

    Wesley D. Adkins Coral Aguirre Mark J. Alden Mazin M. J. Alrawe Eric J. Andersen Abram J. Apodaca Antwanne L. Ash Stanley L. Ayers Nash Barno Savanna S. Bednar Daryl D. Beshirs Carola Buehler Phillip A. Carleton Rogelio Chacon Patchara Chiochankitmun Regino J. Cisneros Perez Christopher W. Cochran Ronnie P. Cook Matthew B. Dallachie Daniel E. Delano Jack H. Dependahl Shelia F. Dixon Lauren A. Dotterweich Frank Eardley Jose E. Echegaray Hernandez Jeanne C. Emmons Michael C. Gacki, Jr. Houssein M. Gale Travis L. Gibbs William M. Godzisz Jose A. Gonzalez Morin Scott R. Graves Luke J. Harding David R. Hazen Mahmoud K. Hiima Eric M. Holloway Mark E. Irsik Edison Joe Craig A. Johnson Jennifer L. King Oleg Kovalev Mollie O. Krablin John P. Kuchta Brian N. LaRose James R. Lockard Michael E. Malloy Jacob D. Miller Rodney Mitchell Brian T. Murphy Steven K. Mynhier, Sr. Craig A. Nass Nathan R. Pawloski Bobby Phongsavanh Albert L. Prather, Jr. Ashley D. Pulkka Joshua E. Richardson Irfan A. Ridha Ammon D. Roe Larry E. Rohloff Roberto Ruiz Fred A. Scott, Jr. Mulmin J. Sellars Shawn R. Sexton Joseph L. Smid Arthur C. Smith Jermaine E. Smith Geoffrey K. Snelling Shane P. Spellman James L. Stevens Casey J. Stover Arnold Taci Joshua T. Takacs Shawn J. Tugwell Tonya M. Turybury Spooford Whitaker, Jr. Jason A. Williams Monique A. Williams Thomas D. Williams Carla M. Wright Vernon R. Yocham Richard W. Youngerman Ahmo Zildzevic

    The following 54 applicants did not have 3 years of experience driving a CMV on public highways with their vision deficiencies:

    Brian D. Beaulieu Anthony Britton Edward M. Brooks Ross A. Busby Riley M. Crumley, Jr. Joseph S. Eaglin Bryan W. Ellis Richard D. Erwin Jose J. Garcia Jesus A. Garza Jerry B. Gibson, Jr. Thomas W. Hall Joshua V. Harrison Michael J. Haubert David M. Iagolla Jacob T. Johnson Shane E. Johnson Todd E. Kelley Timothy W. Kinion Allen Kready Robert A. Kugler Daniel L. Landa W. Kratz Leatherman Miguel M. Levario Leslie Lewis Christopher N. Mahoney Raymundo Maldonado Robert A. Marcum Kyle E. Mason Leonard J. Mazur Richard L. McCance II Joshua J. McCue Robert L. McGowan Jamelle M. Moore Peter J. Neltner Glen L. Nichols Asiarea M. Pattman Lavern D. Penner James R. Preston Elbert J. Price Thomas W. Reddy Thomas L. Rodenborn Ronald B. Shank Daniel H. Smith George Smith Jeffrey Smith Jimmy D. Storms Melanie M. Tate Thomas L. Tomlin Oleksandr M. Trushyk Thomas G. Vowell Norman A. Williams Craig D. Wilson Josef A. Wysocki

    The following 34 applicants did not have 3 years of recent experience driving a CMV with the vision deficiency:

    Vilas R. Adank Joseph C. Anderson Michael D. Birch Wis P. Bordelon Dennis Boyce, Jr. Jeffrey Boyles Larry L. Brownlee Darren J. Burroughs Jason D. DeMaster Robert L. Eldred Shannon E. Harrison Jeffrey D. Johnson Charles D. Jones Daniel R. Kenning Peter A. Ludwig Robert L. McKenzie Aurelio Medoza Richard W. Mullenix Robert S. Notoriano Michael M. Ousley David G. Oyer Quentin R. Palmer David W. Paradis Lawrence B. Reyes Diego R. Rodriguez Samuel L. Short Deneen Stilley Tom L. Stoltz James E. Stubblefield Cedric D. Tobias Dennis R. Trapp Jamal A. Vaughn Larry G. Wenger John M. Zaki

    The following 17 applicants did not have sufficient driving experience during the past 3 years under normal highway operating conditions:

    Grant D. Bolton Carl F. Cryer Wayne E. Egan Michael C. Farley Richard Filion Tim J. Funke Farhad Gholinejad Thomas E. Goodnight Nicholas Martinez Brandon J. Michalko Ralph A. Milliman William Pantoja Julia Alfred A. Polzine Douglas M. Potter Juan C. Ramirez Michael A. Thompson William M. Walk

    The following 3 applicants were charged with moving violations in conjunction with CMV accidents:

    Darrell R. Hammond David T. Miller Jacques W. Rainville

    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:

    Reginald B. Baker Patrick J. Giles Joseph C. Lee

    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:

    David L. Martin Derrick A. Robinson Joseph R. Spranger

    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:

    Eric D. Armstrong Kenneth C. Arnold Richard D. Bailey Michael S. Barnhart Travis K. Bitker Tony A. Bowhall Michael W. Brown Anthony M. Demers Paul T. Fishburn, Jr. Thomas C. Fitzpatrick Maksym R. Fomin Darrell R. Fortner Gregory P. Grimes James D. Grisham Steven M. Heinsohn Robert J. Hemstrought Jacob E. Kuehne Gary L. Logel Richard D. McGuire Tyler J. Nelson Arnold G. Patchin Justin G. Rathert Antonio Reales Dimitre I. Rebreev Mark A. Sanders Glen R. Seipel Jerry A. Slotten John P. Smith Henry L. Stetler Richard B. Stopel Jeremy Trager Charles Walker Dwayne K. Webb Bryan F. Williams Mark Winnicki

    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:

    Michael R. DeLille Jeffrey W. Hawkins Bethany A. Hayward William A. Koldys, Jr. Van C. Pruitt Dean C. Sump

    The following 3 applicants do not meet the vision standard in the better eye:

    Joseph Bahr David L. Denton Sean R. Frank, Jr.

    The following 44 applicants met the current federal vision standards. Exemptions are not required for applicants who meet the current regulations for vision:

    Richard Alfau Francis R. Anaya Helene E. Armistad Richard L. Austin Melvin T. Ayer Michael J. Baca Richard A. Bassett Merle G. Bernhardt Richard C. Besk Rodney S. Burnopp Mauel Cobos Edward L. Cox Joshua P. Doucette Kraig Fisher Brian R. Fredrickson Gregg A. Heinrich Darrell E. Hunter Brad L. Jeffrey Randall Kaiser Bradley A. Kensmoe Richard D. Lindell Jeffrey W. Lowe Nathaniel Lowery Nicholas Mattia Lloyd S. McFerron David R. Nolte Juan Ogando Haley J. O'Neal Cody J. Osland Robert H. Owen Jorge Pedroza Andrew B. Pfeifer David D. Queckboerner Garry A. Reynolds Marvin R. Roetcisoender Leo C. Royer John J. Schaeftlein Jr. Clifford L. Scheel Joseph R. Sherman Robert D. Short Jerome J. Trombly Leone D. Vargason Robert Williams Jack O. Yates

    The following 2 applicants held medical cards valid for less than six months:

    Abelardo J. Guiterrez Edward L. Russell

    The following 3 applicants drove interstate while restricted to intrastate:

    Thomas L. Pelletier Mickey J. Spaulding Douglas E. Weeks

    The following 34 applicants will not be driving interstate, interstate commerce, or are not required to carry a DOT medical card:

    Dwayne P. Arnac Edward L. Arnold Glen M. Asquith Daniel A. Bahm Edward J. Blaskovich Philip L. Bradford Scott Bradford Richard L. Brandt Anthony Brown Lawrence E. Cercle Maurice R. Davis, Jr. Jeffery K. Dorlan Charles J. Ehlert Brett H. Friederichs Luciano G. Garcia Karla D. Holmes Stephen D. Hunt Alvin D. Hunter Thomas M. Kaley, Jr. Eugene A. Leffelman Michael A. Mentzer Robert B. Morris Alexis O. Paulme Jeffrey E. Pennington Kenneth M. Pisano Richard G. Roberts Malcolm S. Rutherford William A. Shaw Clinton Starkey James R. Stout Clinton A. Swartz Eduardo R. Wagner Donald E. Wojtaszek Theodore J. Wuebben

    Finally, the following 14 applicants perform transportation for the federal government, state, or any political sub-division of the state.

    Glenn C. Allen Bradford M. Balint Scott M. Boutwell Bill J. Brookhart James J. Cribbs Gerald M. Garcia Duane R. Greene Billy D. Johnson Darla J. Lloyd Derek E. Madrigal Dru V. Olson Keith A. Smith John L. Umland Daniel R. Zimmerman Issued on: January 21, 2016. Larry W. Minor, Associate Administrator for Policy.
    [FR Doc. 2016-02367 Filed 2-5-16; 8:45 am] BILLING CODE 4910-EX-P
    DEPARTMENT OF TRANSPORTATION Office of the Secretary of Transportation Notice of Funding Availability for the Small Business Transportation Resource Center Program AGENCY:

    Office of Small and Disadvantaged Business Utilization (OSDBU), Office of the Secretary of Transportation. (OST), Department of Transportation (DOT).

    ACTION:

    Notice of Funding Availability for the Southwest Region SBTRC.

    SUMMARY:

    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.

    Funding Opportunity Number: USDOT-OST-OSDBU/SBTRCSOUTHWEST-2016-1.

    Catalog of Federal Domestic Assistance (CFDA) Number: 20.910 Assistance to Small and Disadvantaged Businesses.

    Type of Award: Cooperative Agreement Grant.

    Award Ceiling: $160,000.

    Award Floor: $145,000.

    Program Authority: 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.

    DATES:

    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).

    ADDRESSES:

    Applications must be electronically submitted to OSDBU via email at [email protected] and the OSDBU Regional Assistance Division Manager, Michelle Harris, at [email protected] (copied).

    FOR FURTHER INFORMATION CONTACT:

    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: [email protected].

    SUPPLEMENTARY INFORMATION:

    Table of Contents 1. Introduction 1.1 Background 1.2 Program Description and Goals 1.3 Description of Competition 1.4 Duration of Agreements 1.5 Authority 1.6 Eligibility Requirements 2. Program Requirements 2.1 Recipient Responsibilities 2.2 Office of Small and Disadvantaged Business Utilization Responsibilities 3. Submission of Proposals 3.1 Format for Proposals 3.2 Address, Number of Copies, Deadline for Submission 4. Selection Criteria 4.1 General Criteria 4.2 Scoring of Applications 4.3 Conflicts of Interest Format for Proposals—Appendix A Full Text of Announcement 1. Introduction 1.1 Background

    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.

    1.2 Program Description and Goals

    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 (i.e. The U.S. Department of Commerce's Minority Business Development Centers (MBDCs), Small Business Development Centers (SBDCs), and Procurement Technical Assistance Centers (PTACs), SCORE and State DOT highway supportive services contractors in their region. Utilizing these relationships and their own expertise, the SBTRCs are involved in activities such as information dissemination, small business counseling, and technical assistance with small businesses currently doing business with public and private entities in the transportation industry.

    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.

    1.3 Description of Competition

    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).

    SBTRC Region Competed in This Solicitation: 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 small businesses within the respective geographical region. To this end, the SBTRC must be able to demonstrate that they currently have established relationships within each state in the geographic region with whom they may coordinate and establish effective networks with DOT grant recipients and local/regional technical assistance agencies to maximize resources.

    Cooperative agreement awards will be distributed to the region(s) as follows:

    Southwest Region Ceiling: $160,000 per year Floor: $145,000 per year

    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 100% of salary plus fringe benefits, an on-site Executive Director up to 20% of salary plus fringe benefits, up to 100% of a Project Coordinator salary plus fringe benefits, the cost of designated SBTRC space, other direct costs, and all other general and administrative expenses. Selected SBTRC partners will be expected to provide in-kind administrative support. Submitted proposals must contain an alternative funding source with which the SBTRC will fund administrative support costs. Preference will be given to proposals containing in-kind contributions for the Project Director, the Executive Director, the Project Coordinator, cost of designated SBTRC space, other direct costs, and all other general and administrative expenses. The SBTRC will furnish all labor, facilities and equipment to perform the services described in this announcement.

    1.4 Duration of Agreements

    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.

    Authority

    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.

    1.5 Eligibility Requirements

    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.

    2. Program Requirements 2.1 Recipient Responsibilities (A) Assessments, Business Analyses

    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.

    (B) General Management & Technical Training and Assistance

    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.

    (C) Business Counseling

    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 20 hours of individual or group counseling sessions to small businesses per month. This counseling includes in-person meetings or over the phone, and does not include any time taken to do email correspondence.

    (D) Planning Committee

    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 highway, airport, and transit authorities for the SBTRC's headquarters state must have representation on the planning committee. This committee shall be established no later than 60 days after the execution of the Cooperative agreement between the OSDBU and the selected SBRTC.

    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.

    (E) Outreach Services/Conference Participation

    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, i.e., access to working capital, bonding assistance, business counseling, management assistance and direct referrals to DOT agencies at the state and local levels, and to prime contractors as effective subcontractor firms.

    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.

    (F) Short Term Lending Program (STLP)

    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.

    (G) Bonding Education Program (BEP)

    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.

    (H) Women and Girls in Transportation Initiative (WITI)

    (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 will be conducted on a quarterly basis at an agreeable place and time.

    2.2 Office of Small and Disadvantaged Business Utilization (OSDBU) Responsibilities

    (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.

    3. Submission of Proposals 3.1 Format for Proposals

    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.

    3.2 Address; Number of Copies; Deadlines for Submission

    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 [email protected] and to the Regional Assistance Division Manager, Michelle Harris, at [email protected].

    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).

    4. Selection Criteria 4.1 General Criteria

    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);

    • Approach and strategy (25 points) • Linkages (25 points) • Organizational Capability (25 points) • Staff Capabilities and Experience (15 points) • Cost Proposal (10 points) (A) Approach and Strategy (25 Points)

    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.

    (B) Linkages (25 Points)

    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.

    (C) Organizational Capability (25 Points)

    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 administrative and financial management staff. It will be the responsibility of the successful candidate to not only provide the services outlined herein to small businesses in the transportation industry, but to also successfully manage and maintain their internal financial, payment, and invoicing process with their financial management offices. OSDBU will place an emphasis on capabilities of the applicant's financial management staff. Additionally, a site visit may be required prior to award for those candidates that are being strongly considered. If necessary, a member of the OSDBU team will contact those candidates to schedule the site visits prior to the award of the agreement.

    (D) Staff Capability and Experience (15 Points)

    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.

    (E) Cost Proposal (10 Points)

    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.

    4.2 Scoring of Applications

    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.

    4.3 Conflicts of Interest

    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.

    APPENDIX A Format for Proposals for the Department of Transportation Office of Small and Disadvantaged Business Utilization's Small Business Transportation Resource Center (SBTRC) Program

    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:

    1. Table of Contents

    Identify all parts, sections and attachments of the application.

    2. Application Summary

    Provide a summary overview of the following:

    • 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.

    3. Understanding of The Work

    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.

    4. Approach and Strategy

    • 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.

    5. Linkages

    • 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.

    6. Organizational Capability

    • 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.

    7. Staff Capability and Experience

    • 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.

    8. Cost Proposal

    • 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.

    9. Proof of Tax Exempt Status 10. Assurances Signature Form

    Complete the attached Standard Form 424B ASSURANCES-NON-CONSTRUCTION PROGRAMS identified as Attachment 1.

    11. Certification Signature Forms

    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.

    Signed Conflict of Interest Statements

    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.

    12. Standard Form 424

    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.

    Issued in Washington, DC, January 20, 2016. Brandon Neal, Director, Office of Small and Disadvantaged Business Utilization, Office of the Secretary, U.S. Department of Transportation.
    [FR Doc. 2016-02368 Filed 2-5-16; 8:45 am] BILLING CODE 4910-9X-P
    DEPARTMENT OF TRANSPORTATION [Docket No. DOT-OST-2015-0221 (Formerly Docket Number DOT-OST-2012-0080)] Agency Requests for Renewal of a Previously Approved Information Collection: Small Business Transportation Resource Center (SBTRC) Regional Field Offices Intake Form (DOT F 4500) AGENCY:

    Office of Small and Disadvantaged Business Utilization (OSDBU), Office of the Secretary of Transportation (OST), DOT.

    ACTION:

    Notice of request for comments.

    SUMMARY:

    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 Federal Register (Vol. 80, No. 218) (Formerly Docket Number DOT-OST-2012-0080), informing the public of OSDBU's intention to extend an approved information collection. The collection involves the use of the Regional Field Offices Intake Form (DOT F 4500), which documents the type of assistance provided to each small business that is enrolled in the program database. The information will be used to ascertain whether the program is providing services to its constituency, the small business community, and is done so in a fair and equitable manner. The information collected is necessary to determine whether small businesses are participating in DOT funded and DOT assisted opportunities.

    We are required to publish this notice in the Federal Register by the Paperwork Reduction Act of 1995, Public Law 104-13.

    DATES:

    Written comments should be submitted by: March 9, 2016.

    ADDRESSES:

    Your comments should be identified by Docket No. DOT-OST-2015-0221 and may be submitted through one of the following methods:

    Office of Management and Budget, Attention: Desk Officer for U.S. Department of Transportation, Office of Information and Regulatory Affairs, Office of Management and Budget, Docket Library, Room 10102, 725 17th Street NW., Washington, DC 20503.

    Email: [email protected].

    Fax: (202) 395-5806. Attention: DOT/OST Desk Officer.

    FOR FURTHER INFORMATION CONTACT:

    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 [email protected] (email).

    SUPPLEMENTARY INFORMATION:

    Title: U.S. Department of Transportation, Office of Small and Disadvantaged Business Utilization (OSDBU).

    Affected Public: Representatives of OSDBU's SBTRC Regional Field Offices and the Small Business community on a national basis.

    Type of Request: Extension of a Currently Approved Collection of Information.

    Abstract: In accordance with Public Law 95-507, an amendment to the Small Business Act and the Small Business Investment Act of 1953, OSDBU is responsible for the implementation and execution of DOT activities on behalf of small businesses, in accordance with Sections 8, 15 and 31 of the Small Business Act (SBA), as amended. The Office of Small and Disadvantaged Business Utilization also administers the provisions of Title 49, of the United States Code, Section 332, the Minority Resource Center (MRC) which includes the duties of advocacy, outreach, and financial services on behalf of small and disadvantaged businesses and those certified under CFR 49 parts 23 and or 26 as Disadvantaged Business Enterprises (DBE).

    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 data can assist the Field Offices in developing a business plan or adjusting their business plan to increase its ability to market its goods and services to buyers and potential users of their services.

    Respondents: SBTRC Regional Field Offices.

    Annual Estimated Number of Respondents: 100.

    Frequency: The information will be collected quarterly.

    Annual Estimated Number of Responses: 400.

    Estimated Total Annual Burden on Respondents: 600 hours per year (90 minutes per response to complete each Intake Form).

    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.

    Authority:

    The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended; and 49 CFR 1:48.

    Issued in Washington, DC, on February 1, 2016. Habib Azarsina, OST Privacy and PRA Officer.
    [FR Doc. 2016-02369 Filed 2-5-16; 8:45 am] BILLING CODE 4910-9X-P
    DEPARTMENT OF THE TREASURY Community Development Financial Institutions Fund Notice of Funds Availability Inviting Applications for the Fiscal Year (FY) 2016 Funding Round of the Capital Magnet Fund

    Announcement Type: Announcement of funding opportunity.

    Funding Opportunity Number: CDFI-2016-CMF

    Catalog of Federal Domestic Assistance (CFDA) Number: 21.011

    DATES:

    Electronic applications for must be received by 5:00 p.m. Eastern Time (ET), March 30, 2016.

    Key Dates:

    FY 2016 CMF Program Funding Round Critical Deadlines for Applicants Description Deadline Time
  • (Eastern time- ET)
  • Submission method
    SF-424 Mandatory form March 16, 2016 11:59 p.m. ET Electronically via Grants.gov. Last day to contact CMF Program Staff March 28, 2016 5:00 p.m. ET CDFI Fund Helpdesk: 202-653-0421 or [email protected]. CMF Application and Required Attachments March 30, 2016 11:59 p.m. ET Electronically via Awards Management Information System (AMIS).

    Executive Summary: The Capital Magnet Fund (CMF) is administered by the Community Development Financial Institutions Fund (CDFI Fund). Through the CMF, the CDFI Fund provides financial assistance grants to Community Development Financial Institutions (CDFIs), and to qualified Nonprofit Organizations that have the development or management of affordable housing as one of their principal purposes. All awards provided through this Notice of Funds Availability (NOFA) are subject to funding availability.

    I. Program Description

    A. Authorizing Statutes and Regulations: The CMF was established through the Housing and Economic Recovery Act of 2008 (HERA), which added section 1339 to the Federal Housing Enterprises Financial Safety and Soundness Act of 1992. Under (HERA), the Government Sponsored Enterprises (GSEs), Federal National Mortgage Association (Fannie Mae) and the Federal Home Loan Mortgage Corporation (Freddie Mac), are required to set aside annual allocations equal to 4.2 basis points for each dollar of their unpaid principal balances of total new business purchases, of which 25 percent must be deposited into a reserve fund for the HOPE for Homeowners Program for FY 2016, and, of the remaining amount available, the Housing Trust Fund will receive 65 percent of the funds, and the CMF will receive 35 percent of the funds. The Federal Housing Finance Agency (FHFA), acting as the GSEs' conservator, temporarily suspended these allocations before they began, and Congress appropriated $80 million to fund an initial round of the CMF in FY 2010. In December 2014, the FHFA lifted its suspension of the GSEs' allocation and directed the GSEs to begin allocating funds for the CMF. This NOFA announces that the CDFI Fund will make CMF Awards when such funds are made available through the GSEs' FY 2015 annual allocation. The regulations that govern the CMF are the interim rule (12 CFR part 1807), which has been simultaneously published for comment with this NOFA, and the CDFI Fund's environmental regulations at 12 CFR part 1815 (environmental quality regulations).

    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. History: The CDFI Fund was established by the Riegle Community Development Banking and Financial Institutions Act of 1994 to promote economic revitalization and community development through investment in and assistance to CDFIs. Since its creation in 1994, the CDFI Fund has awarded over $2 billion to CDFIs, community development organizations, and financial institutions through the Capital Magnet Fund (CMF), Community Development Financial Institutions Program (CDFI Program), the Native American CDFI Assistance Program (NACA Program), the Bank Enterprise Award Program (BEA Program), and the Financial Education and Counseling Pilot Program. In addition, the CDFI Fund has allocated more than $43 billion in tax credit allocation authority through the New Markets Tax Credit Program (NMTC Program) and has obligated $852 million in bond guarantees to Eligible CDFIs through the CDFI Bond Guarantee Program.

    C. Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards (2 CFR part 200): The Uniform Administrative Requirements codify financial, administrative, procurement, and program management standards that Federal award-making agencies must follow. Per the Uniform Administrative Requirements, when evaluating award applications, awarding agencies must evaluate the risks to the program posed by each Applicant, and each Applicant's merits and eligibility. These requirements are designed to ensure that Applicants for Federal assistance receive a fair and consistent review prior to an award decision. This review will assess items such as the Applicant's financial stability, quality of management systems, history of performance, and single audit findings. In addition, the Uniform Administrative Requirements include guidance on audit requirements and other award compliance requirements for award Recipients.

    D. Priorities: The CMF priorities are to attract private capital for and increase investment in the Development, Preservation, Rehabilitation, or Purchase of Affordable Housing for primarily Extremely Low-Income, Very Low-Income, and Low-Income Families, as well as Economic Development Activities, which, In Conjunction With Affordable Housing Activities, implement a Concerted Strategy to stabilize or revitalize a Low-Income Area or Underserved Rural Area. In this NOFA, the CDFI Fund will implement these priorities by funding Applications that propose to: (i) Finance and/or support rental Affordable Housing Projects in which a minimum of 20 percent of the units in each Project are targeted to Very Low-Income households and/or Extremely Low-Income Families; or finance and/or support Homeownership Projects in which a minimum of 20 percent of the units in each Project are targeted to Low-Income Families; and (ii) leverage a higher proportion of private capital to finance and/or support Affordable Housing Activities and Economic Development Activities. Further, the CDFI Fund will fund Applications serving geographically diverse areas of economic distress, including Metropolitan and Underserved Rural Areas.

    II. Federal Award Information

    A. Funding Availability: The amount available for FY 2016 awards through this NOFA will be the amount that is transferred to the CDFI Fund by the GSEs for the Capital Magnet Fund. No Congressionally appropriated funds are anticipated through the FY 2016 CMF Program Funding Round. Based on quarterly reports filed by the GSEs with the Securities and Exchange Commission, the CDFI Fund anticipates receiving approximately $80 million to fund CMF Awards in FY 2016. However, the final amount allocated to the CMF by the GSEs will likely not be determined before March 2016, and thus the anticipated amount may differ from the actual allocated amount. HERA prohibits the CDFI Fund from obligating more than 15 percent of the available CMF funding in the aggregate to any Applicant, its Subsidiaries and Affiliates in the same funding round. Affiliated entities are not allowed to apply separately under this NOFA. While the exact dollar amount of the funding cap cannot be established until the total amount available for CMF Awards is known, the FY 2010 CMF Program Funding Round is illustrative of how the funding cap will be implemented. In FY 2010, the amount appropriated for CMF Awards was $80 million, the funding cap was $12 million, and CMF Awards ranged from $500,000 to $6 million.

    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. Types of Awards: The CDFI Fund will provide CMF Awards in the form of grants. CMF Awards must be used to support the eligible activities as set forth in 12 CFR 1807.301. CMF Awards cannot be “passed through” to third-party entities, whether Affiliates, Subsidiaries, or others, to undertake the eligible activities set forth in 12 CFR 1807.301, without the prior written approval of the CDFI Fund.

    C. Limitation on Number of CMF Awards: An Applicant may receive only one award through the FY 2016 CMF Program Funding Round. An Applicant, its Subsidiaries, or Affiliates also may apply for and receive an award through the CDFI Program, CDFI Bond Guarantee Program, Native American CDFI Assistance (NACA) Program, Bank Enterprise Award (BEA) Program, or New Markets Tax Credit (NMTC) Program, but only to the extent that the activities proposed for CMF Awards are different from those activities for which the Applicant received an award under another CDFI Fund program. The CDFI Fund has determined that for purposes of this rule, such different activities are those proposed Projects that do not involve funding from any other CDFI Fund program.

    D. Anticipated Start Date and Period of Performance: The CDFI Fund anticipates the period of performance for the FY 2016 CMF Program Funding Round will begin in the Spring of 2016. The period of performance for each CMF Award begins with the date that the CDFI Fund issues the notice of award and continues until the end of the Investment Period (as defined in 12 CFR 1807.104), or as otherwise set forth in the Assistance Agreement, during which time the Recipient must meet certain performance goals.

    E. Eligible Activities: An Applicant may submit an Application for a CMF Award to support or finance activities that attract private capital for and increase investment in (i) the Development, Preservation, Rehabilitation, or Purchase of Affordable Housing for primarily Low-, Very Low- and Extremely Low-Income Families, and (ii) Economic Development Activities. CMF Awards may only be used as follows: (i) To provide Loan Loss Reserves, (ii) to capitalize a Revolving Loan Fund, (iii) to capitalize an Affordable Housing Fund, (iv) to capitalize a fund to support Economic Development Activities, (v) for Risk-Sharing Loans, or (vii) to provide Loan Guarantees. No more than 30 percent of a CMF Award may be used for Economic Development Activities. The amount available to any Recipient for Direct Administrative Expenses is limited to no more than 5 percent of its CMF Award, and may only be used to facilitate the Recipient's use of its CMF Award for the eligible activities.

    III. Eligibility Information

    A. Eligible Applicants: In order to be eligible to apply for a CMF Award, an Applicant must either be a Certified CDFI or a Nonprofit Organization, as defined in 12 CFR 1807.104. Table 1 indicates the criteria that each entity type must meet in order to be eligible for a CMF Award pursuant to this NOFA:

    Table 1—Applicant Eligibility Requirements Entity type Eligibility requirements Certified CDFI • Has been in existence as a legally formed entity for at least 3 years prior to the Application deadline under this NOFA; • Has been determined by the CDFI Fund to meet the CDFI certification requirements set forth in 12 CFR 1805.201 and has received official notification from the CDFI Fund that it meets all such requirements as of the date of this NOFA; • Its CDFI certification has not expired; • Has not been notified by the CDFI Fund that its certification is in default or has been terminated; • In cases where the CDFI Fund provided Certified CDFIs with written notification that their CDFI certification was extended, the CDFI Fund will consider the extended certification date (the later date) to determine whether those Certified CDFIs meet this eligibility requirement. Nonprofit Organization • Has been in existence as a legally formed entity for at least 3 years prior to the Application deadline under this NOFA; • 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 • Demonstrates that at least thirty-three and one-third percent of its total assets (loan portfolio and investments) is dedicated to the development or management of affordable housing.

    Any Applicant that does not meet the criteria in Table 1 is ineligible to apply for a CMF Award under this NOFA.

    Table 2—Additional Eligibility Requirements Application type and submission overview through Grants.gov and Awards Management Information System (AMIS) • Applicants must submit the required Application documents listed in Table 4.
  • • The CDFI Fund will only accept Applications that use the official application templates provided on the Grants.gov and AMIS websites. Applications submitted with alternative or altered templates will not be considered.
  • • Applicants will submit the required documents in two locations: (1) Grants.gov and (2) AMIS. ○ Grants.gov: Applicants must submit the OMB SF-424 Mandatory (Application for Federal Assistance) form. ○ AMIS: Applicants must submit all other required Application materials. ○ All Applicants must register in the Grants.gov and AMIS systems to submit an Application successfully. The CDFI Fund strongly encourages applicants to register as early as possible. • Grants.gov and the SF-424 Mandatory form: ○ The SF-424 must be submitted in Grants.gov before the other Application materials are submitted in AMIS. Applicants are strongly encouraged to submit their SF-424 as early as possible via the Grants.gov portal. ○ If the SF-424 is not accepted by Grants.gov, the CDFI Fund will not review any material submitted in AMIS and the Application will be deemed ineligible. • AMIS: ○ AMIS is a new enterprise-wide information technology system that is replacing the myCDFI Fund portal and that will be used to submit and store organization and Application information with the CDFI Fund. ○ Applicants are only allowed one submission in AMIS. Employer Identification Number (EIN) • An Applicant must submit electronically a copy of the letter from the IRS as evidence that the Applicant has been assigned its own unique EIN. • The CDFI Fund will reject an Application submitted with the EIN of a parent or Affiliate organization. • The CDFI Fund will deem an Application incomplete if it does not include an IRS document that verifies the Applicant's EIN (a tax return is not an acceptable form of IRS documentation). DUNS number • Pursuant to OMB guidance (68 FR 38402), an Applicant must apply using its unique DUNS number in Grants.gov. • The CDFI Fund will reject an Application submitted with the DUNS number of a parent or Affiliate organization. Awards Management Information System (AMIS) • Each Applicant must register as an organization in AMIS and submit all required Application materials through the AMIS portal. • The Authorized Representative must be included as a “user” in the Applicant's AMIS account. • 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. 501(c)(4) status • Pursuant to 2 U.S.C. 1611, a 501(c)(4) any organization that engages in lobbying activities is not eligible for the receipt of CMF Award. Compliance with Federal civil rights requirements • An Applicant may not be eligible to receive an award if proceedings have been instituted against it in, by, or before any court, governmental agency, or administrative body, and a final determination within the last 3 years indicates the Applicant has violated any of the following laws: Title VI of the Civil Rights Act of 1964, as amended (42 U.S.C. 2000d); Section 504 of the Rehabilitation Act of 1973 (29 U.S.C. 794); the Age Discrimination Act of 1975, (42 U.S.C. 6101-6107), and Executive Order 13166, Improving Access to Services for Persons with Limited English Proficiency.

    Further, the following describes additional considerations applicable to prior award Recipients or Allocatees under any CDFI Fund program:

    B. Prior award Recipients or Allocatees: Applicants must be aware that success in a prior round of any of the CDFI Fund's programs is not indicative of success under this NOFA. Prior award Recipients or Allocatees under any CDFI Program are eligible to apply under this NOFA, except as noted in the following table:

    Table 3—Eligibility Requirements for Applicants Which Are Prior Award Recipients Criteria Description Pending resolution of noncompliance The CDFI Fund will consider an Application submitted by an Applicant that has pending noncompliance issues if the CDFI Fund has not yet made a final determination as to whether the Applicant is in default of any of its previously executed agreement(s). Default or Noncompliance status • The CDFI Fund will not consider an Application submitted by an Applicant that has been notified by the CDFI Fund in writing that it is in default of a previously executed agreement under any CDFI Fund program, at the time of the Application deadline, unless otherwise indicated by the CDFI Fund in writing. The CDFI Fund will not consider an Application submitted by an Applicant that has been notified by the CDFI Fund in writing that it is noncompliant with an FY 2015 agreement, or with agreements for fiscal years thereafter, under any CDFI Fund program, at the time of the Application deadline, unless otherwise indicated by the CDFI Fund in writing. • The CDFI Fund will not consider any Applicant that has defaulted on a CDFI program loan within five years of the Application deadline. Undisbursed award funds and calculations (general) An Applicant that has funds from a prior CDFI Fund program that have not been disbursed, as defined in (a)-(d) below, as of the Application deadline will not be eligible for a CMF Award. (a) The CDFI Fund will include the combined undisbursed funds of the Applicant and its Affiliates. (b) Balances on undisbursed award funds cannot exceed 5 percent of the combined BEA Program awards made to the Applicant in FYs 2012, 2013, and 2014. (c) Balances on undisbursed award funds cannot exceed 5 percent of the combined CDFI/NACA Program awards made to the Applicant in FYs 2012, 2013, and 2014. (d) The undisbursed award funds calculation does not include award funds for: (i) Which the Recipient has submitted a full and complete disbursement request before the Application deadline; (ii) an award that has been terminated or de-obligated; (iii) an award that does not have a fully executed award agreement; and (iv) the tax credit allocation authority made available through the NMTC Program.

    C. Contact the CDFI Fund: Accordingly, Applicants that are prior Recipients and/or Allocatees under any CDFI Fund program are advised to: (i) Comply with requirements specified in an assistance agreement, award agreement, allocation agreement, bond loan agreement, or agreement to guarantee and (ii) contact the CDFI Fund to ensure that all necessary actions are underway for the disbursement of any outstanding balance of a prior award(s). An Applicant that is unsure about the disbursement status of any prior award should contact the CDFI Fund by sending an email to [email protected]. All outstanding reports and compliance questions should be directed to the Certification, Compliance Monitoring, and Evaluation helpdesk by email at [email protected] or by telephone at (202) 653-0423. The CDFI Fund will not respond to Applicants' reporting, compliance, or disbursement telephone calls or email inquiries that are received after 5:00 p.m. ET on March 28, 2016 until after the Application deadline. The CDFI Fund will respond to technical issues related to AMIS Accounts through 5:00 p.m. ET on March 30, 2016 via AMIS Service Requests, or at [email protected], or by telephone at (202) 653-0422.

    D. Cost sharing or matching fund requirements: Not applicable.

    E. Other Eligibility Criteria:

    (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 http://www.cdfifund.gov for more details).

    (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.

    IV. Application and Submission Information

    A. Address to Request Application Package: Application materials can be found on Grants.gov and the CDFI Fund's Web site at www.cdfifund.gov/cmf. Applicants may request a paper version of any Application material by contacting the CDFI Fund Help Desk by email at [email protected] or by phone at (202) 653-0421.

    B. Content and Form of Application Submission: All Application documents must be submitted electronically through Grants.gov and AMIS, the CDFI Fund's internet-based interface. 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. Only the Authorized Representative or Application Contact Person designated in AMIS may submit the Application through AMIS.

    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 www.cdfifund.gov/cmf, instructions for accessing and submitting an Application. Detailed Application content requirements are found in the Application and related guidance documents.

    Table 4—Funding Application Documents Application document Submission format Required? Standard Form (SF) 424 Mandatory form Fillable PDF in Grants.gov Required for All Applicants. CMF Application Form AMIS Required for All Applicants. ATTACHMENTS TO THE APPLICATION: IRS Documentation of Organization's EIN PDF in AMIS Required for All Applicants. Audited Financial Statements (most recent 3 fiscal years) PDF in AMIS Required for All Applicants. State Charter or Articles of Incorporation designating that the Applicant is a nonprofit or not-for-profit entity under the laws of the organization's State of formation PDF in AMIS Required for only for Applicants that are not Certified CDFIs. A certification demonstrating tax exempt status from the IRS PDF in AMIS Required for only for Applicants that are not Certified CDFIs. Articles of incorporation, by-laws or other document demonstrating the Applicant has a principal purpose of managing or developing affordable housing PDF in AMIS Required for only for Applicants that are not Certified CDFIs.

    The CDFI Fund strongly encourages Applicants to start the Grants.gov registration process as soon as possible (refer to the following link: http://www.grants.gov/web/grants/register.html) as it may take several weeks to complete. An Applicant that has previously registered with Grants.gov must verify that its registration is current and active.

    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. Dun and Bradstreet Universal Numbering System (DUNS):

    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. System for Award Management (SAM):

    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 https://www.sam.gov.

    E. Submission Dates and Times:

    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:

    Table 5—FY 2016 CMF Deadlines for Applicants Document Deadline Time—eastern time (ET) Submission method SF-424 Mandatory form March 16, 2016 11:59 p.m. ET Electronically via Grants.gov. CMF Application and Required Attachments March 30, 2016 11:59 p.m. ET Electronically via AMIS.

    (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 SF-424 as early as possible in the Grants.gov portal since submission problems may impact the ability to submit the overall Application.

    (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 [email protected] with a subject line of “Late Application Submission Request.”

    (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.

    V. Application Review Information

    A. Criteria: CMF Awards will be made based on Applicants' experience and ability to use a CMF Award to support Affordable Housing Activities and Economic Development Activities in accordance with the criteria set forth below.

    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 (e.g., use of the CMF Award to secure additional capital, including third-party capital, prior to investing into Projects to capitalize an Affordable Housing Fund or Revolving Loan Fund);

    (ii) Through reinvestment of CMF Award dollars during the Investment Period into additional Projects (e.g., planned re-investment of the CMF Award and leveraged funds); and/or

    (iii) At the project level (e.g., use of the CMF Award to invest in Projects with total Eligible Project costs in excess of the CMF Award investment).

    (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.

    B. Review and Selection Process

    (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) Internal Application Review and Initial Award Determination: After the Applications have been reviewed and scored by external reviewers, they will be forwarded to CDFI Fund staff. Applications will be ranked and reviewed in descending order of the external reviewer score. CDFI Fund staff will conduct additional due diligence on highly ranked Applicants and analyze additional programmatic and financial risk factors including, but not limited to: Financial stability; quality of management systems and ability to meet award management standards; reports and findings from audits; and the Applicant's ability to effectively implement Federal requirements. Award amounts may be reduced as a result of this analysis. The CDFI Fund may also reduce awards sizes from requested amounts based on certain variables, including an Applicant's loan disbursement activity, total portfolio outstanding, and similar factors.

    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.

    VI. Federal Award Administration Information

    A. Award Notification: Each successful Applicant will receive an email “notice of award” notification from the CDFI Fund stating that its Application has been approved for an award. Each Applicant not selected for an award will receive an email stating that a debriefing notice has been provided in its AMIS account.

    B. Administrative and National Policy Requirements: The CDFI Fund may, in its discretion and without advance notice to the Recipient, terminate the award or take other actions as it deems appropriate if, prior to entering into an Assistance Agreement, information (including an administrative error) comes to the CDFI Fund's attention that adversely affects: The Recipient's eligibility for an award; the CDFI Fund's evaluation of the Application; the Recipient's compliance with any requirement listed in the Uniform Requirements; or indicates fraud or mismanagement on the Recipient's part.

    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:

    Table 6—Requirements Prior To Executing an Assistance Agreement Requirement Criteria Failure to meet reporting requirements If a Recipient is a prior CDFI Fund award Recipient or Allocatee under any CDFI Fund program and is not current on the reporting requirements set forth in the previously executed assistance, award, allocation, bond loan agreement(s), or agreement to guarantee, as of the date of the Notice of Award, the CDFI Fund reserves the right, in its sole discretion, to delay entering into an Assistance Agreement and/or to delay making a Payment of CMF Award, until said prior Recipient or Allocatee is current on the reporting requirements in the previously executed assistance, award, allocation, bond loan agreement(s), or agreement to guarantee. Please note that automated systems employed by the CDFI Fund for receipt of reports submitted electronically typically acknowledge only a report's receipt; such acknowledgment does not warrant that the report received was complete, nor that it met reporting requirements. If said prior Recipient or Allocatee is unable to meet this requirement within the timeframe set by the CDFI Fund, the CDFI Fund reserves the right, in its sole discretion, to terminate and rescind the Notice of Award and the CMF Award made under this NOFA. Failure to maintain CDFI Certification A Recipient must be a Certified CDFI or a Nonprofit Organization prior to entering into an Assistance Agreement. Pending resolution of noncompliance If, at any time prior to entering into an Assistance Agreement under this NOFA, an Applicant that is a prior CDFI Fund award Recipient or Allocatee under any CDFI Fund program has submitted reports to the CDFI Fund that demonstrate noncompliance with a previous assistance, award, or allocation agreement, but the CDFI Fund has yet to make a final determination regarding whether or not the entity is in default of its previous assistance, award, allocation, bond loan agreement, or agreement to guarantee, the CDFI Fund reserves the right, in its sole discretion, to delay entering into an Assistance Agreement and/or to delay making a Payment of CMF Award, pending full resolution, in the sole determination of the CDFI Fund, of the noncompliance. If said prior Recipient or Allocatee is unable to meet this requirement, in the sole determination of the CDFI Fund, the CDFI Fund reserves the right, in its sole discretion, to terminate and rescind the Notice of Award and the CMF Award made under this NOFA. Default or Noncompliance status If, at any time prior to entering into an Assistance Agreement, the CDFI Fund determines that a Recipient is in default of a previously executed agreement with the CDFI Fund and the Recipient has been provided written notification of such determination, the CDFI Fund can delay entering into an Assistance Agreement, until the Recipient has cured the default, if applicable, by taking actions the CDFI Fund has specified within the specified timeframe. Further, if, at any time prior to entering into an Assistance Agreement, the CDFI Fund determines that a Recipient is noncompliant with an FY 2015 agreement, or with agreements for fiscal years thereafter, under any CDFI Fund program, the CDFI Fund can delay entering into an Assistance Agreement, until the Recipient has cured the noncompliance by taking actions the CDFI Fund has specified within the specified timeframe. If the Recipient is unable to meet the cure requirement, if applicable, within the specified timeframe, the CDFI Fund may terminate and rescind the Assistance Agreement and the CMF Award made under this NOFA. Final Default and Sanctions If the CDFI Fund has found the Recipient in final default of a prior executed agreement and provided notification of sanctions, the CDFI Fund may terminate and rescind the Assistance Agreement and the CMF Award made under this NOFA within the time period specified in such notification. Compliance with Federal civil rights requirements The CDFI Fund will terminate and rescind the Assistance Agreement and the CMF Award made under this NOFA if, prior to entering into an Assistance Agreement under this NOFA, the Recipient receives a final determination, made within the last 3 years, in any proceeding instituted against the Recipient in, by, or before any court, governmental, or administrative body or agency, declaring that the CMF Award Recipient has violated the following laws: Title VI of the Civil Rights Act of 1964, as amended (42 U.S.C.2000d); Section 504 of the Rehabilitation Act of 1973 (29 U.S.C. 794); the Age Discrimination Act of 1975, (42 U.S.C. 6101-6107), and Executive Order 13166, Improving Access to Services for Persons with Limited English Proficiency. Do Not Pay 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 CDFI Fund reserves the right, in its sole discretion, to rescind an award if the award Recipient is identified as ineligible to be a Recipient on the Do Not Pay database. Safety and soundness If it is determined the Recipient is or will be incapable of meeting its CMF Award obligations, the CDFI Fund will deem the Recipient to be ineligible or require it to improve safety and soundness conditions prior to entering into an Assistance Agreement.

    C. Assistance Agreement: Each Applicant that is selected to receive an award under this NOFA must enter into an Assistance Agreement with the CDFI Fund in order to become a Recipient and receive Payment. Each CMF Award under this NOFA generally will have a period of performance that begins with the date of the notice of award and continues until the end of the Investment Period. However, the Assistance Agreement shall also include a 10-year affordability period in addition to the Investment Period.

    (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. Paperwork Reduction Act: Under the Paperwork Reduction Act (44 U.S.C. chapter 35), an agency may not conduct or sponsor a collection of information, and an individual is not required to respond to a collection of information, unless it displays a valid OMB control number. If applicable, the CDFI Fund may inform Applicants that they do not need to provide certain Application information otherwise required. Pursuant to the Paperwork Reduction Act, the CMF Program Application has been assigned the following control number: 1559-0036.

    E. Reporting: The CDFI Fund will require each Recipient that receives a CMF Award through this NOFA to account for and report to the CDFI Fund on the use of the CMF Award. This will require Recipients to establish administrative controls, subject to applicable OMB Circulars and guidance. The CDFI Fund will collect information from each such Recipient on its use of the CMF Award at least once following Payment and more often if deemed appropriate by the CDFI Fund in its sole discretion. The CDFI Fund will provide guidance to Recipients outlining the format and content of the information required to be provided to describe how the funds were used.

    The CDFI Fund may collect information from each Recipient including, but not limited to, an Annual Report with the following components:

    Table 7—Reporting Requirements Criteria Description Single Audit Narrative Report (or like report) The Recipient must submit, via AMIS, a Single Audit Narrative Report for each year of its period of performance notifying the CDFI Fund whether it is required to have a single audit pursuant to OMB Single Audit requirements. Single Audit (if applicable) (or similar report) A Recipient that is a non-profit entity that expends $750,000 or more in Federal awards during its fiscal year must have a single audit conducted for that year. If a Recipient is required to complete a Single Audit Report, it should be submitted to the Federal Audit Clearinghouse. See 2 CFR part 200, subpart F-Audit Requirements in the Uniform Federal Award Requirements. For-profit award Recipients will be required to complete and submit a similar report directly to the CDFI Fund. CMF Annual Report All Recipients must submit a CMF Annual Report to the CDFI Fund on uses of the CMF Award (including transactional data on eligible activities and Projects, and customer profiles) via the Community Investment Impact System (CIIS). Explanation of Noncompliance (as applicable) or successor report If the award Recipient fails to meet a performance goal or reporting requirements, it must submit the Explanation of Noncompliance via AMIS.

    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. Financial Management and Accounting: The CDFI Fund will require Recipients to maintain financial management and accounting systems that comply with Federal statutes, regulations, and the terms and conditions of the CMF Award. These systems must be sufficient to permit the preparation of reports required by general and program specific terms and conditions, including the tracing of funds to a level of expenditures adequate to establish that such funds have been used in accordance with the Federal statutes, regulations, and the terms and conditions of the CMF Award.

    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.

    VII. Agency Contacts

    A. Availability: The CDFI Fund will respond to questions and provide support concerning this NOFA and the Application between the hours of 9:00 a.m. and 5:00 p.m. ET, starting on the date of the publication of this NOFA until the close of business on the third day preceding the Application deadline. The CDFI Fund will not respond to questions or provide support concerning the Application that are received after 5:00 p.m. ET on said date, until after the Application deadline. CDFI Fund IT support will be available until 5:00 p.m. ET on date of the Application deadline. Applications and other information regarding the CDFI Fund and its programs may be obtained from the CDFI Fund's Web site at http://www.cdfifund.gov/cmf. The CDFI Fund will post on its Web site responses to questions of general applicability regarding the CMF.

    B. The CDFI Fund's contact information is as follows:

    Table 8—Contact Information Type of question Telephone No. (not toll free) Email addresses CMF 202-653-0421 [email protected]. CDFI Certification 202-653-0423 [email protected]. Compliance Monitoring and Evaluation 202-653-0423 [email protected]. Information Technology Support 202-653-0422 [email protected].

    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. Communication with the CDFI Fund: The CDFI Fund will use AMIS to communicate with Applicants and Recipients, using the contact information maintained in their respective AMIS accounts. Therefore, the Recipient and any Subsidiaries, signatories, and Affiliates must maintain accurate contact information (including contact persons and authorized representatives, email addresses, fax numbers, phone numbers, and office addresses) in its AMIS account(s). For more information about AMIS please see the Help documents posted at http://amis.cdfifund.gov/s/Training.

    Authority:

    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.

    Dated: February 2, 2016. Mary Ann Donovan, Director, Community Development Financial Institutions Fund.
    [FR Doc. 2016-02372 Filed 2-3-16; 4:15 pm] BILLING CODE 4810-70-P
    DEPARTMENT OF THE TREASURY Office of the Comptroller of the Currency Agency Information Collection Activities: Information Collection Renewal; Comment Request; Privacy of Consumer Financial Information AGENCY:

    Office of the Comptroller of the Currency (OCC), Treasury.

    ACTION:

    Notice and request for comment.

    SUMMARY:

    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 Federal Register concerning each proposed collection of information, including each proposed extension of an existing collection of information and to allow 60 days for public comment in response to the notice.

    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.”

    DATES:

    Comments must be received by April 8, 2016.

    ADDRESSES:

    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 [email protected]. You may personally inspect and photocopy comments at the OCC, 400 7th Street SW., Washington, DC 20219. For security reasons, the OCC requires that visitors make an appointment to inspect comments. You may do so by calling (202) 649-6700 or, for persons who are deaf or hard of hearing, TTY, (202) 649-5597. Upon arrival, visitors will be required to present valid government-issued photo identification and submit to security screening in order to inspect and photocopy comments.

    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.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    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 Federal Register concerning each proposed collection of information, including each proposed extension of an existing collection of information, before submitting the collection to OMB for approval. To comply with this requirement, the OCC is publishing notice of the proposed collection of information set forth in this document.

    The OCC is proposing to extend OMB approval of the following information collection:

    Title: Privacy of Consumer Financial Information.

    OMB Control No.: 1557-0216.

    Description:

    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:

    § 1016.4(a)—Disclosure (institution)— Initial privacy notice to consumers requirement—A national bank or Federal savings association must provide a clear and conspicuous notice to customers and consumers that accurately reflects its privacy policies and practices.

    § 1016.5(a)(1)—Disclosure (institution)—Annual privacy notice to customers requirement—A national bank or Federal savings association must provide a clear and conspicuous notice to customers that accurately reflects its privacy policies and practices not less than annually during the continuation of the customer relationship.

    § 1016.8—Disclosure (institution)— Revised privacy notices—Before a national bank or Federal savings association discloses any nonpublic personal information in a way that is inconsistent with the notices previously given to a consumer, the institution must provide the consumer with a clear and conspicuous revised notice of the institution's policies and procedures, provide the consumer with a new opt out notice, give the consumer a reasonable opportunity to opt out of the disclosure, and the consumer must not opt out.

    § 1016.7(a)—Disclosure (institution)—Form of opt out notice to consumers; opt out methods—Form of opt out notice—If a national bank or Federal savings association is required to provide an opt out notice under § 1016.10(a), it must provide to each of its consumers a clear and conspicuous notice that accurately explains the right to opt out under that section. The notice must state:

    • 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.

    §§ 1016.10(a)(2) and 1016(c)—Consumers must take affirmative actions to exercise their rights to prevent financial institutions from sharing their information with nonaffiliated parties—

    • 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.

    §§ 1016.7(h) and 1016(i)—Reporting (consumer)—Duration of right to opt out—Continuing right to opt out—A consumer may exercise the right to opt out at any time. A consumer's direction to opt out is effective until the consumer revokes it in writing or, if the consumer agrees, electronically. When a customer relationship terminates, the customer's opt out direction continues to apply to the nonpublic personal information collected during or related to that relationship.

    Type of Review: Regular.

    Affected Public: Businesses or other for-profit; individuals.

    Estimated Annual Number of Respondents: 2,706,750.

    Estimated Total Annual Burden Hours: 693,284 hours.

    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.

    Dated: February 2, 2016. Mary H. Gottlieb, Regulatory Specialist, Legislative and Regulatory Activities Division.
    [FR Doc. 2016-02324 Filed 2-5-16; 8:45 am] BILLING CODE 4810-33-P
    DEPARTMENT OF THE TREASURY Office of Foreign Assets Control Unblocking of Specially Designated Nationals and Blocked Persons Pursuant to Executive Order 13288, as Amended by Executive Order 13391, and Executive Order 13469 AGENCY:

    Office of Foreign Assets Control, Treasury.

    ACTION:

    Notice.

    SUMMARY:

    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.”

    DATES:

    OFAC's actions described in this notice are effective as of February 3, 2016.

    FOR FURTHER INFORMATION CONTACT:

    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).

    SUPPLEMENTARY INFORMATION:

    Electronic and Facsimile Availability

    The SDN List and additional information concerning OFAC sanctions programs are available from OFAC's Web site (www.treasury.gov/ofac). Certain general information pertaining to OFAC's sanctions programs is also available via facsimile through a 24-hour fax-on-demand service, tel.: 202/622-0077.

    Notice of OFAC Actions

    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.

    Individuals 1. TAVEESIN, Nalinee (a.k.a. TAVEESIN, Nalinee Joy; a.k.a. TAWEESIN, NALINEE), 14th Floor of Modern Tower, Tower 87/110 Sukhumvit 63, Wattana, Bangkok 10110, Thailand; 33 Soi Soonvijai 4, Rama IX Road, Soi 26, Success Tower, Huai Khwang, Bang Kapi, Bangkok 10320, Thailand; 19-8 Soi Passana 3, Sukhumvit Road, Pakanong Nua, Wattana, Bangkok 10110, Thailand; 33 Soi Soonwichai 4 Bangkapi, Huaykhwang, Bangkok 10310, Thailand; DOB 12 Feb 1960; alt. nationality Thailand; alt. citizen Thailand; Passport Z066420 (Thailand); Managing Director (individual) [ZIMBABWE]. 2. NDLOVU, Rose Jaele; DOB 27 Sep 1939; Passport AD000813 (Zimbabwe); Spouse of Sikhanyiso Ndlovu (individual) [ZIMBABWE]. 3. NDLOVU, Sikhanyiso Duke; DOB 04 May 1937; Passport ZD001355 (Zimbabwe); Deputy Minister of Higher and Tertiary Education (individual) [ZIMBABWE]. 4. MIDZI, Amos Bernard Muvenga; DOB 04 Jul 1952; Minister of Mines and Mining Development (individual) [ZIMBABWE]. 5. SAKUPWANYA, Stanley; DOB circa 1945; Deputy Secretary for Disabled and Disadvantaged (individual) [ZIMBABWE]. Entities: 1. NDLOVU MOTORWAYS, c/o Sam Nujoma Street/Livingston Avenue, Harare, Zimbabwe [ZIMBABWE]. 2. AGRICULTURAL DEVELOPMENT BANK OF ZIMBABWE (a.k.a. AGRIBANK; a.k.a. AGRICULTURAL BANK OF ZIMBABWE), 15th Floor, Hurudza House, 14-16 Nelson Mandela Avenue, Harare, Zimbabwe; Box 369, Harare, Zimbabwe; Phone No. 263-4-774426; Fax No. 263-4-774556 [ZIMBABWE]. 3. INFRASTRUCTURE DEVELOPMENT BANK OF ZIMBABWE (a.k.a. ZIMBABWE DEVELOPMENT BANK), ZDB House, 99 Rotten Row, Harare, Mashonaland East, Zimbabwe; P.O. Box 1720, Harare, Zimbabwe; Phone No. 263-4-7501718; Fax No. 263-4-7744225 [ZIMBABWE]. Dated: February 3, 2016. John E. Smith, Acting Director, Office of Foreign Assets Control.
    [FR Doc. 2016-02364 Filed 2-5-16; 8:45 am] BILLING CODE 4811-AL-P
    DEPARTMENT OF THE TREASURY Office of Foreign Assets Control Unblocking of Specially Designated Nationals and Blocked Persons Pursuant to the Foreign Narcotics Kingpin Designation Act AGENCY:

    Office of Foreign Assets Control, Treasury.

    ACTION:

    Notice.

    SUMMARY:

    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).

    DATES:

    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.

    FOR FURTHER INFORMATION CONTACT:

    Assistant Director, Sanctions Compliance & Evaluation, Department of the Treasury, Office of Foreign Assets Control, Washington, DC 20220, Tel: (202) 622-2420.

    SUPPLEMENTARY INFORMATION:

    Electronic and Facsimile Availability

    This document and additional information concerning OFAC are available from OFAC's Web site at www.treasury.gov/ofac or via facsimile through a 24-hour fax-on demand service at (202) 622-0077.

    Background

    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 Emirates); alt. Passport H-825326 (United Arab Emirates) (individual) [SDNTK].

    Dated: February 3, 2016. John E. Smith, Acting Director, Office of Foreign Assets Control.
    [FR Doc. 2016-02379 Filed 2-5-16; 8:45 am] BILLING CODE 4810-AL-P
    DEPARTMENT OF THE TREASURY Office of Foreign Assets Control Sanctions Action Pursuant to Executive Order 13712 AGENCY:

    Office of Foreign Assets Control, Treasury.

    ACTION:

    Notice.

    SUMMARY:

    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).

    DATES:

    OFAC's action described in this notice was effective February 3, 2016.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    Electronic and Facsimile Availability

    The SDN List and additional information concerning OFAC sanctions programs are available from OFAC's Web site (www.treasury.gov/ofac). Certain general information pertaining to OFAC's sanctions programs is also available via facsimile through a 24-hour fax-on-demand service, tel.: 202/-622-0077.

    Notice of OFAC Actions

    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].

    Dated: February 3, 2016. John E. Smith, Acting Director, Office of Foreign Assets Control.
    [FR Doc. 2016-02371 Filed 2-5-16; 8:45 am] BILLING CODE 4810-AL-P
    DEPARTMENT OF THE TREASURY Internal Revenue Service Quarterly Publication of Individuals, Who Have Chosen To Expatriate, as Required by Section 6039G AGENCY:

    Internal Revenue Service (IRS), Treasury.

    ACTION:

    Notice.

    SUMMARY:

    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.

    Last name First name Middle name/Initials ABRAMSOM NEIL ALBEN REMINGTON ACTON BROOKE ASHLEY ADAM DAVID NEAL AGAR-WAITE LESLIE ELIZABETH AGGERSBJERG KASPER AHLGREN ROSS DAVID AHMAD ZEBA TAMANNA AICHI JIRO AKERMAN SUZANNE L ALDCROFT GEORGE WILLIAM ALLAN FRASER KIRKWOOD ALLIBERT INES MAGDELEINE MARIE AMOG MELCHOR FALLORINA AN JENNIFER SOHYUN ANDERSON CURTIS LESLIE ANTHONY JACQUELINE SELMA ARATO JUDITH MARION ARBESMAN PAIGE LOLA ARMSTRONG JINNY ASHENAFI TEODROS ATAYA RABEA F ATWATER DOROTHY ATWOOD MIRJAM BEATRICE ATWOOD PERRY DALL AU DERRIC THOMAS WAIHO AUSTIN SHELBY LEIGH AUYANG SUNNY YING CHI AU-YEUNG CANDACE ASHLEY AW ETHAN YOW TYNG AXFORD ERIC CHARLES AXFORD MICHELLE ROBERTA BADAR VICTOR MINOR BAGLEY JONATHAN THOMAS BAGLEY ROBERT LEE BALDINI NORA IRENE BALFOUR ALASTAIR ALBERT DAVID BALLHORN SCOTT LEWIS BARKHURST JUDSON JOSEPH BARR ALISON LESLIE BARR NORMA ELEANOR BARRELET JEAN ETHEL BARRY DANIEL BRUCE BARTON CAROLINE VICTORIA BARVIR ROSANNE BASKWILL NICHOLAS STEPHEN BAUMBERGER FELLMANN DANICA BEATRICE BAUMGARTNER HEIDI GERTRUDE BAYLIS CHARLES STEWART LORIMER BAYLIS DONNA MAE BECHTEL CHRISTIAN BELDI ICILIO BELL ADAM VERDUN BELL TRACY BENEDICT JOHN ROSS BENSON CARLTON LEE BENSON CHERI ANN BERLOFF NATALIA GENNADIEVNA BERMUDEZ LANCE DION BHARWANI JABEEN BILLINGS JOHANNA LYN BINDER BUKHARD ANDREW BIRD ARTHUR D BISHOP ANDREA MEGAN BLANCHARD LOUISE MARIAN BLANCPAIN RANI ERICA BLONDEEL PHILLIP NICOLAS BLOUIN MARIE HELENE BLY JARED DOUGLAS BODDEN ERIK MARK ALEXANDER BOERLIN JESSICA SARA BOERLIN REBECCA LOUISE BOLLER-HUBER DANIELLE MARIE BOLLER BOLSINGER YANNICK KEVIN BONELL ROBERT DOUGLAS BONNETT KRISTOPHER LEE BORDEN LARS ERIC BOULTER CAYLEEN CONSTANCE ANGELICA BOULTER JULIEN WINFORD BOURQUE LEON BOVAY BROOKE LOUISE BOWMAN CECIL REGINALD BRADBEE CHERYL ANN BRADFORD STEVEN JAMES BRADLEY JULIA VAN VLECK BRANDLI GERDA REGULA BRANDLI-BASLER EVELYN BEATRICE BRATTY DIANE MARIE ROSINA THERESE BREDESON JAMES CLEMENS BROGER CAROLE MARIE DAVITT BROWN ANDREW THOMAS BROWNE LORA JEAN BRUCE DAVID JAMES BUCK GARTH ORVILLE BUCKLER ETHEL MARGUERITE BUCKSPAN MARTIN BARRY BURGER CRAIG JILL KATHLEEN BURGESS GWENDOLINE MAY BUSER MANUEL ERICH BUTLER JOHN XAVIER BUTOW SUSAN ELIZABETH BYAM JO ANNE BYAM STUART PETER C.H. VON ALVENSLEBEN WENDULA MARIA CAI WEI CAIRNCROSS SARAH WHITTLESEY CALDWELL SARAH LENORE CAMPBELL DONNA ELAINE CAMPBELL TARA SHEREINA CAPACCIOLI ALBERTO CAPELLO MAUREEN LEE CAROON VALERIE LYNN CARPENTER ERIN MAIGREAD CARROLL LAURA ANN CARTER DAVID BLAKE CARUEL FRANCOIS JAMES CARVETH IDA JEAN CAVNER RORY CRAIG CEBALLOS RICARDO ANDRES CORREA CERMAK IRENE VERA CHADWICK BRIAN PAIGE CHAI YOUNGMI NOH CHAMBERS VALERIE ANGELA CHAN ALEXANDER CHEH-HWAN CHAN HECTOR IVAN TY CHAN MONICA CHAN SUSAN PIKSAN FUNG chang flora chia-I CHANG LEE SHU CHANG WARREN CHAPMAN CHRISTIE LAIRD CHARETTE GERARD PAUL CHARLES FLORENCE ELAINE JACKSON CHARLES NICOLE LABRINE CHARMAN PATRICIA LYNN CHAU PRISCILLA AMY chell kimberly joy CHEN CLAUDIA CHEN KEVIN CHEN MARY YU HWA CHEN PAO TZU CHENG YIN HSI CHERN ANGELA CHESLUK-BARTON TRACEY DEONA CHEUNG THOMAS CHUFOO CHEVION PELEG SHOSHAN CHIANG LEE LIAN CHIAO ALICE CHIAVI JULIANA (JULIA) CHIEN JEFFREY SHENG-PING CHISHICK RYAN GERALD SHANE CHMELICEK JOHN THOMAS CHOE REGINA WOONJEONG CHOEGYAL RINCHEN HARRY CHARLES CHOI MYUNG JAE CHOO JODI HUIJUAN CHOO RONI AKEAKAMAI CHOW PORTIA BICK YUEN CHRISSOVELONI ZOE CHRISTIE DEREK WAYNE CHRISTOFFEL JOHANNES THOMAS CHUA LYDIA JIA-LI CHUN SUNG HWAN CHUNG ABIGAIL HUI-JUAN CHUNG ANDREW B CHUNG SHIRLEY THERESE CLANFIELD JANICE LYNN CLARK-LINDH CONNOR ANDREW CLOWER ROBERT WAYNE CONLEY MICHAEL CHARLES CONNORS MATTHEW JOHN CORNFORTH DELBERT NEVILLE CORNISH PETER JAMES SCHUYLER COSTELLO KENNETH EDUARD COSULICH TIMOTHY PAOLO ALFREDO COTTER JILL ERIN COURVOISIER JEANNE DANIELLE COX DOUGLAS LEROY CRACKEL GAVIN JAMES CREE MARILYN WANDA CRESSMAN NADINE LOU CROTON PETER GARTH CROWE TIMOTHY ALAN CYMBAL IRENE CYR ALICE LORRAINE DAHL JUDITH MARIE D'AILLY KAREN RUTH D'AILLY WOUTER ADRIAAN DAME ELVA IRENE DANNHOF ANNE KATHARINA DARCH SHENANDOAH DAVIDS LEO DAVIDSON RALPH CURRIE DAVIES STACY JAYNE DAVIS MARK ANDREW DAVITT KENNETH PATRICK DAY AARON DE AYALA MARIANA BEATRIZ ZOBEL DE BOER PIET J DE LA GUARDIA JOSE MIGUEL DE LUCA ANTONIO DE LUCA JOANN KATHERINE BINDER DE MATTOS JOSE AUGUSTO ARNIZAUT DE PAREDES DONNA A CANEVARI DE REUS STEVEN ROCHUS DEEGAN MICHAEL JOHN DEFFNER GEORGE MICHAEL DEL CORRAL ANA LUCIA PEREZ DELOUME JOHN LOUIS DELWART JANINE LOUISE DENIS CHRISTINE MARIE DENNEHY THOMAS MICHAEL DESOUZA KRYSTEN MARIE DETTLING GERTRUD DI LEONARDO MARTHA JEAN DIEBERT DIXIE TENA DIANE DOBIAS AGNES MARIE DODDS HOWARD EDWIN DOEHRING RADKA STYLEROVA DOIRON CAROL MARIE DOIRON JOHN FITZGERALD DOUGLAS SUSAN ELIZABETH DOWLING ERIC MORGAN DOWN ANTON JAMES DROUIN MARC DUBACH FABIO DOMINIC DUBLANKO JOAN ELLEN DUBUIS ANNE GABRIELLE DUECK THEODORE CARL DUFF TAMI-JO RACHEL DUMONT LOUIS ALEXANDRE DUNHAM KENT EDWARD DVORAK BRADLEY SCOTT DYCK REBECCA ANN DYKE HEATHER LOUISE EBERIE KATHLEEN WHITING ECHAVARRI DANIEL FELIPE EGGENBERGER KEVIN MARC KURT EGGLETON MICHAEL JAMES EGLI MICHAEL THOMAS EISENBERG JUDITH ELLEN EKERS RYAN DANE ELFORD KELCY THOMAS ELIASON LILYAN FAYE ELLIS MELISSA MEDLAND ELLIS NICK HO EL-SAHEB HADY NABIL SAMEEH ENGSTROM JENNIE VICTORIA ENSIGN MARK RAYMOND ENSOR HUGH MCCRACKEN EPPLEN ROBIN BENJAMIN ESSELBURN JOSEPH JUN ESTES JAMES MARTIN ETTER SUSANNE FRANZISKA EVANS DAVID OSCAR EVANS JAMIE LLOYD EVANS JANE BROWNING EVANS PENNY ANN EVANS VICTOR BRIAN EXNER LAURA L FAKNER STEPHANIE MAXINE FANG ROSE-JEAN CHANG FARR CHARLEEN DOROTHY FEEHELY LILLIAN MARGARET FEHR JESSICA NADINE FERGUSON ALEXANDER MURRAY FERREIRA KAREN JOYCE FESTIVAL MEGAN BARBARA FISCH PATRICIA ANNE FISHER JOANNE FLETCHER KAREN LEA FLINN PATRICIA FLUCKIGER ERIC FLUECK WERNER THOMAS FLYNN KATHERINE ELIZABETH DOROTHY FOERSTER ANDREA MARGARETA FONSECA GABRIEL ENRIQUE ADOLFO FONTAINE ANNE CLAIRE COURVOISIER FORGUSON CHRISTOPHER REED FORJAN EDWARD FOSTER DAVID WILLIAM FOWLER DANIEL FONTENELE FRAISE AYMERIC FRANKLIN HOLLY ALICE FRETZ ISABELLE MARIA FRIDAY LEE RENIER FRIESEN ANNA JOY FU LAUREN JIAYU FUNG RONALD CHUN-PONG FUNK TAMMY SUSAN FURITSCH ROBERT FUST ATTILA FREDERICK GAFFNER TODD MICHAEL GAGNE CAROLE JACQUELINE GAGNE PATRICK GARCIA GEORGINA M. GARDNER HARRY ROBERT GARLOCK CHRISTOPHER TODD GAULT III JOHN CLIFTON GAVAZZI ANNA GEORGINA GEIGER-SCHATTNER SUSAN LYNN GERMAIN ANNE ELIZABETH GETTY ROBERT GUNNER GILBERT CATHY LYNN GIMPEL JACK FRANK GLAESKE STEVEN DALE GLASSBERG DEBORAH GLOGER WOLFGANG PAUL HERMAN GNEHM-WHITING AMANDA HALL GOETOMO MICHAEL XIU-HAO GOH DANNY ALEXANDER VALDES GOLDBERG KENNETH ARTHUR GOLDSMITH JOHN HENRY GOLDSTEIN CAROL JEAN. GOLDSTEIN JAY ELLIS GORMAND PATRICE GORRELL GUY RONALD MICHAEL GRAHAM CHARLES F GRAHAM JAMES FREDERICK GRAHAM KAREN ANN GRAHAM RAE ANN GRIFFIN NAOMI NAKAGUCHI GRILLOT OLIVIER C GUGELMANN MICHELE ELSA LEONIE GUIDA RONALD MARK GWALTNEY LAMAR ANDERSON GYSELS JOHN FRANK HAAS CHRISTOPHER MICHAEL HABIB ANNE MARIE HACKMAN JAMES CLEMENS HACKMAN JEANETTE ALDERFER HADDEN DUSTIN RYAN HADLEY ANITA LIPPENS HADLEY JENNIFER KATE HAGIHARA TOMOYUKI HAINKE BERND HAIR MICHAEL LLOYD HALATSIS MARC ERIC HALL EVANGELINE JOY HALL KAREN NOWLENE HALL PAMELA BARBARA HALUSCHAK ALEXANDRA GAIL HALUSCHAK MATTHEW EVAN HAMILTON LINDSAY KRISTINA FRASER HAN ALEC HAN CHEE UNG HAN DYLAN YONG-DING HAN WAGNER HANNIGAN THERESA RACHELLE HANSON SHANNON ROCHELLE YVONNE HARALABAKOS ARISTIDIS HARALABAKOS GEORGE HARALABAKOS JOANNA HARRIS JONATHON JEFFREY HARRIS KAREN MARIE HARRISON SOPHIA CAMILLE HASLER ASTRID DIANE HAYWARD JUSTIN SEAN HAZE ANDREW JAMES HEAD THAYER VIRGINIA HEALEY GRACE ELLEN HEATH DAVID MARTIN HECKES FRANK MARIANO MELCHOR HEGGLIN OLIVER LEO HEINEN-KONSCHAK ERIC HEMPEL GREGORY PHILIPP HEMPEL MELANIE GERMAINE HENDERSON RUTH MUNCY HENGY PHILIPPE OTHMAR HENNIGFELD CLAUDIA ANNA ERIKA HENRIQUEZ ALEXANDRA HERRMANN MARTINA HERSEY DEMETRI ALEXANDER HERZFELD WINFRIED CHESTER HERZLINGER STEVEN ALLEN HEWITT LINDA MARIE HEWSON PHILIP ERNEST HEYER-BOOT MARTINE HENRIETTE HIMEL DANIELLE STACEY HO DAPHNE HODSON THOMAS EDWARD HOEFFLEUR-THALIN LESLIE ARLENE HOEPKER NIKOLAS CHARLES HOFFMANN MARION KATHARINA DELHEES HOHLFELD JUDITH ANNE HOLDEN JOHN PHILLIP HOLTEN MICHELLE LOUISE HOLTOF NIELS JOZEF HOLTZ INGRID SOPHIA HONEGGER MARKUS D HONHON MURIEL SANDRA ELISE HOOVER CATHERINE MARIE HOSGOOD DOMINIC EDWARD HOUSLEY aka ERNEST HOUSLEY JAMES HSIN CHUNG HERNG HSIN MEI LEN HSU TANYA S. HSU-HO MANDY BEIFEN HUANG ALISON HUBER ALENA IDA HUDEC ALVIN THEODORE HUMPLIK CARMEN BEATRICE HUNTER EMILY MARGUERITE HUNTING ERIKA ANNE SZABO HUSTLER JOSEPH RANDOLPH IEZZI PHILIP LAURENCE IKEDA RUMIKO ISDELL-CARPENTER SIMON ISLER MELISSA CROSS JAGORINEC JOHN JAGUAR JADE JAIN ANITA JAREK AMY BETH JENNINGS MARK CRITCHLEY JENNINGS MICHELLE BERNADETTE JEON HONG SEOK JESBERGER JAMES ARTHUR JO JUSTIN JOHNS MARY ANN JOHNSON ALLISON LINDSAY JOHNSON DEREK IAN JOHNSON SHEREE LIN JOHNSTON MEGAN KATHLEEN JOHNSTONE CHERYL LYNN JONES LIANE ROCHELLE JOO JENNIFER JANET JORGENSEN SHARON LEE JORSTAD ANNE KATRINE JORSTAD INGER SOFIE JOSEPH ROBERT ANTHONY KAEMPF CLAUDIA IRENE KALAYOGLU BELKIS KANAN GAVIN KANG JOAN OAK KANG KIMBERLEY KAPUST HANS-DIETER KATZ ANDREW STEVEN KATZMAN DAVIDA KAUFMAN SARAH KAWASHIMA KAZUMITSU PAUL KAYE EDWARD KENNETH KEDAR DAFNA SARAI KELEN JENNIFER SUSAN KELLER CHRISTOPHER THOMAS OTMAR KELLER EVELYN ELIZABETH KELLER GABRIELLA MARIA KOENIG KELLER KARIN KELLERHALS KASPAR PETER KERR AMANDA EVELYN KEYES BRETT JOEL KHANNA AYESHA KHASHOGGI ASSIA AMR KIESWETTER LUIS EMILIO MOUYNES KIM BRIAN GUNWOO KIM BRIGITTE KIM JASON HYO KIM KENNETH KIM KYUNG SUN KIM LORIE MINSUM KIM MI SOOK KIM PETER KIM TEDDY KIM YANG SUE KIM YOUNG JEON KIMMEL ROBERT L KING BARBARA ANNE KING LEWIS ARLO KING THEODORE WALKER CHENG-DE KINGSBURY PATRICK JOHANN KIRK MELANIE GRACE KITAGAWA CHRISTNE ARISA KLEIN MARIA KLEIN SETH DAVID KNOUSE KRISTEN JOY KNUFF BARBARA LOIS KODAMA NAOKO JUNE NAMIOKA KOHLER KATHLEEN ANN KOHLER STACEY LYNN KOHLER STEPHANIE ANN KOKKONOS ALEXIS IOANNIS KONISHI TAKAAKI KONZ NICOLE MARIA KOO DENNIS DONG-BEUM KOO DONG JIN KOO JAE MO KOSTYK DEBRA LEE Kramer-Palmer Michele KRANC SAFFIRE HANNA KROEKER JANICE LILLIAN KUGEL LARISSA ERIN KUHN ROSEMARIE KUO RICHARD KURMANN DENISE MARIE KWAN MELVYN SHIU-MING LAI JESSE JUAN-XIANG LAI NIKI WING CHAU LAM JENNIFER FUNG SANG LANEVILLE PETER PAUL LANKFORD JEREMIAH ALEXANDER LARDNER BOBBIE JO LARGE JOANNE ELIZABETH LARRAIN MARIA PATRICIA LATHROP JAMES JEFFERS LATHROP WILLIAM BROWN LAUGHERY ELIZABETH LAUGHERY GREGORY JOSEPH LAURIE SEAN DAVID LAVIN LISA MARIE LEASURE JOHN ASHLEY LECLAIR DAVID JOHN LEE AIMEE WEN LEE CHIN-HAO LEE EUGENIA QIU-TING LEE GRACE SUM YEE LEE IVAN JIN-HO LEE LEO YAO LEE MIN SANG LEE NANCY WEN LEE SEAN SHI-ZHE LEGERTON WILFRED JOHN LEHR RITA JOANNE LENNARSON ANN CATHERINE LENZINI ARNOLD ETTORE LEONG DARYL ZHAN WEI LESUEUR RICHARD MILO LEUNG ANDREW YAT-FAI LEURQUIN VERONIQUE MARIE LEUSINK LINDSEY ELIZABETH LEVERT EVELINE MONIQUE LEVETTO JR MARIO J LI KAREN KAY LI MICHELLE MAN YEE LIANG JEANNIE TUNG LIEN CHUN-HSIUNG LIM JESSICA SIAO-JING LIM JONATHON WEI-REN LIM JUNG WON LIN ANDERSON BEIH-TZUN LIN FAY LIAO LIU AN-PING LIU JING YI LIU KELVIN CHIN-CHAN LJUTOW ANDRE ALEXANDER LOGAN SANDRA ELLEN LOH NICHOLAS LOO CRYSTAL XIAO-WEI LOPEZ MICHAEL ANDREW LOPEZ REBECCA HERNAEZ LOUGH SANDRA LEE LOUIE RAYMOND SEE CHUN LOUTFI KARIM ROBERT LOVELL WILSON JOSEF LOWE TRINA LYNN LOWRY DONNA ELAINE LU NICHOLAS LUDERS JACQUELINE ANNE LUSTIGUE AGNES JUDITH MA DANNY WAI KIU MAC NAUGHTON MICHAEL DAVID MACDONALD DIANA MACDONALD WENDY ELIZABETH MACINTYRE MARY ELIZABETH MACLELLAN ROBERT LEWIS MACNUTT DEBRA MARIE MACRI MICHAEL BRIAN MACY GORDON THOMAS MACY RICHARD HOOE MADSEN JENNIFER JO MAGEE YUSHI CHRISTOPHER MAH MEIXING MAISCH BARBARA MAJAK DONNA FLORINE MAKEPEACE CAROLINE JANE MALESKU JENNIFER MANA MALUS ROCHELLE SCHULTZ Manley E Philippa MANNING JAMES ARTHUR FORT MARKLEY ROBERT KARL MARTO-MALINOWSKI OCTAVIA ANNA MATHER MARY JOAN MATTHEWS JEREMY JOSEPH MAUE ERIKA ILSE MAUTNER-MARKHOF DIANA MARIE MAYER DENNYS MC NEIL DAVID MC NEIL DAVID MCAUSLAND STUART ROY MCCORMACK NAOMI ETHEL MCCOY LIZA MARIE MCCUTCHEON SUSAN REBECCA MCDONALD DENISE ELISE ANN MCGONIGAL DANIELA MARIA MCKNIGHT WESLEY ERNEST MCLEAN DELLA MARJORIE MCLEOD LINDA GAIL MEESTERS SASKIA CORINNA MEIJER MARGOT MEINERTZ KIRSTEN MARGARET MEINTEL DEIRDE ANN MELA JOHN M MELKA DENNIS NICHOLAS MELTON NOEL KENNETH MENA CATALINA FRANCISCA MENA FRANCISCO JAVIER MENARD JAMES DOUGHTY MENDENHALL MICHEL VINCENT MERTES BARBARA FRANZISKA MERVILLE PATRICK CHRISTIAN MEYER MICHAEL PETER MIAN ISMAT SAIRA. MIDGETT JOYCE MARIE MIHM KIMBERLY ANN MILLER ARTHUR E MILLER GORDON MILES MILLER JEAN MILTENBURG JENNIFER ELIZABETH MISLIN MARC PATRICK MITHANI SHAZMA SHIRAZ MOHR NADIM BERNARD MOLINE REBECCA MARIANNE MONTGOMERY DANA CATHERINE MOON EUGENE YOONJOO MOON JOHN WESLEY MORA JAIME ANDRES LOPEZ MORGAN JESSICA RIEL MORIN JENNIFER MORRIS EDITH IZABELLA MORSE EWART ALEXANDER MORTON MILDRED ANN MOSKAL SUSAN REBECCA MOSKOWITZ PAMELA DIANE MOUAWAD CAROLINE BITAR MOUYNES CARLOS ROBERTO MULLER MARGUERITE THERESA NAF PATRICK SEAN NAKAJIMA HIROAKI ROBERT NASH DAVID ANTHONY nee ANDREWS KATHERINE ELIZABETH SPENCE nee FAVOT ALLISON COLLEEN DWYER NEESEN CHRISTOFFER NEIRYNCK TATU MARY NELSEN HEIDI MARIE NG CRYSTAL CHERWYN NG JANELL MOO EN NG KAI-LING NG MING YIN NGIM AUGUSTIN DA-WEI NGUYEN HUNG QUOC NICOLAIDES MARIA NIXON ELDON FORD NOH HOWARD YUNMIN NOLAN JULIA ESTHER NOVOSEL RITA ANDREA NOWAK MICHELE ANN NUSBAUMER SEGOLENE MARIE NUTTER RICHARD WALLACE O'DONNELL JAMES DENIS OETKER ANTONIA NICOLA GEORGIA OLMSCHEID RITA MARIE OLONDRIZ FRANCESCA MARA MALLARI OLSON RUTH ANNE OLTHUIS SANDRA LYNN ONEAL SARAH SOPHIE ONG JUSTIN GUANG-XI ONYSHKO DANIEL JOHN OOI RUI TING OPHEK MICHAEL ISAIAH OSA-WYSER ANNETTE OTTO CHRISTIAN KLAUS PAGEL HANNAH NICOLE PAHL JONAH BENJAMIN PAHL PAMELA JANE PAKEMAN BETSY GENE PAN RICHARD WEI YANG PAPERNICK MICHAEL DARRIN PAPERNICK WENDY ROBIN PARDO SONIA MARIA KABA PARK JINYOUNG CHRISTINA PARK NEUNG MOON PARK SANGMO JEFF PARK SUK YUNG PARKER NICOLA CAROLINE PATEL SHEILLA CHITTARANJAN PATMORE CARL ALVIN PATTERSON-CUERVO GLORIA ROSSANA PAZ BRISENO SARA GABRIELA PEARCE JONATHON SAMUEL PECKER LAURE PEDERSON KRISTEN LUE PEK SHAWN JUNJIE PENTECOSTES MARILYN SUMER PEROTTO MARTIN ALEJANDRO PERRY DAVID EMERY PERRY LISA CAITLYN PETER CYRIL PATRICK PETRAS JOAN ELLEN PFENNINGER RICHARD PAUL PHARAON LLANA GHAITH PHILIPS CAMILO J. PHILLIPS ROBERT SCOTT PHUA PAMELA HUI-LUN PIERCE SUSAN LYNN PIMENTEL DANIEL PHILIP CAETANO PIRO WOLFGANG MANFRED PITCHER JANET ZANIER PLANKEY IVONNE ELISABETH PLETT RONALD ABE POON SUEN SON POUR-AMMANN EVA MARGRIT POZZI MARCO ANDREAS PRADA ERICA ANNE PRASAD VIKRAM PRETELLI EVA CHRISTINA PUDVAH MICHAEL BERNARD PUNG SOKE MAY QAMAR DIMITRI KHALED BASILE QUAIL ERIC WILLIAM QUAN EDWARD QUINN HOLLY MARIE QUINN JR THOMAS REGIS RADOVANOVITCH ROLF PETER RAFUSE LINDA LEE RAMAPRASAD RAJIV RAPPAPORT LISKA SYLVIA ANN RASMUSSEN BROOKE NICHOL RASMUSSEN DEBORA ELIZABETH RATCHFORD WILLIAM JOSEPH RATNAM JUVINA RAUME CRAIG DOUGLAS RAYBURN GEOFFREY FRANKLIN READ KENNETH JOHN REEDY WILLIAM JOSEPH REGIER HILDA MARGARETA REICHE ALEXANDER WILLIAM ANTON REICHMAN JOAN PETRA REID ALISON HEATHER REID ANDRIA CAROL ANN REID MARY KATHRYN REIKIE BARBARA JEAN REIMER JOHN JACOB REIMER LUKE ALVAH REINHARDT PAUL ALAN REMINGTON ROBERT JAMES RESSEL VERA IRENE REUTER KATHARINA SIMONE REUTERSKIOLD CHRISTINA J REYNOLDS STEVEN CAMPBELL RHOADES MARLENE ELAINE RICHARDS PATRICIA LYNN RICHARDSON PAULA JEAN RIDDELL ERICA MARIE RIDDELL MORAG ANNE RISEMAN ANDREW LEE ROBERSON-CONSUL BRADLY J ROBERTS CANDIS ROBINSON ELIZABETH ARLENE ROBINSON JAMES BARRY ROBINSON JOSEPH LORENCE ROBINSON PAMELA ROBINSON ROBERTA RAE ROCHAT HELENE NATHALIE RODEMERS CLAUDIA ROETHEL CORNELIA ROGERS DAVID PETER ROLLEMAN JACQUELINE MARGARET ROOSEN-RUNGE CHERILYN FRANCIS ROSE CAROL FRANCES ROSE ROBERT PATRICK ROSS FIONA MARGARET ROUTLEDGE DAVID GLENN ROUX NICOLE ANDREE ROYER ALLAN THEODORE RUDDOCK CHERYL KAY RUNKLE SEAN MARK RUOSS-CAMENZIND MARIANN VIRGINIA RUPARELIA RAJIV SUDHIR RUSSELL ALBERT LEE RUSSELL DELILAH RUTH SAAR MICHAEL WERNER SAHGAL GIORGIO GAUTAM SALES JOSEPH GORDON SALTARELLI LAURA ANGELA SAMMET DIANE KAY SAMYNATHAN BENJAMIN AMALDAS SANCHEZ ROBERTO ANTONIO SANDERS ROBERT ALLAN SANDRI GIAN ANDREA SANDS DAPHNE ANN SANDS SUZANNE SANDSTROM VIRVE SANTOSO RAYMOND LEE SARDINHA JULIE ANN SASAKI YUTO ZACHARY SAUCIER MARY DUBOIS SAXER STEFANIE ANNE SCALES DIANA ANNE-MARIE SCALES MICHAEL THOMAS SCALZO FRANCESCA MARIA SCHAEPPI ALESSANDRO SCHAEPPI MASSIMO SCHAER BEATRICE SCHAWINSKY DANIEL ELIA SCHEIDEGGER HEATHER ANN SCHIEFERDECKER YVONNE JOANNE SCHLATTER YVES ERIC SCHMID MARC WILLIAM SCHMID-KUHNHOFER MARIE-THERESE SCHMIDT-HEBBEL ANDRES SCHMIDT-HEBBEL VIVIAN SCHMIDT-RADDE OLIVER JOHANN SCHNEIDER CLAIRE SOPHIE SCHNYDER CHRISTOPHE LUC SCHOYER MARNIX KAREL NICO SCHREIBER KAREN IRENE SCHREIBER MARNIE ANN SCHUTTE MARK ANTHONY SCOTT MICHAEL PROWER SCOTT SEAN SEBASTIAN SEMBER JEFFERY PAUL SETLIFF JR ERNEST GORE SEYFFERTITZ KARL T. G. MARIA SHAFER JAMES RINEAR SHAFER SHARON ANN SHANK REBECCA SUSAN SHANNON JEFFREY JOHN SHAUNESSY TERENCE KEVIN SHAW BRIAN MATTHEW SHAYO RAYMOND DAVID SHEN JASON SHIH CHIEH SHERIDAN REBECCA KATHLEEN SHIAU BO BOR-YEU SHIAU CHANG YING SHIELDS DEBORAH ANNETTE SHIELDS LANA LEIGH SHIU JEFFREY MA SIEBENMANN MANUEL SIEBENS WILLIAM CARTER SIM SOON-SIANG KIMBERLY SIMON HANNAH BERIT BERNADETTE SIRIVIRIYAKUL VORAYA THIRAKOMEN SLATER CHARLES CAREY SLEGERS EDNA DOROTHEA SMITH ALLEN DOUGLAS SMITH CAROL PATRICIA SMITH CHESTER JUNIOR SMITH ELISE BECKET SMITH KAREN GAY SMITH KRISTINA KELLY SMITH LINDA ANNE SMITH MIQUELYN JEAN SMITH THEODORE DANIEL SNIDER WESTON JAMES SNOOK GALEN WALTER SOLIS GERARDO ALBERTO SORENSON REBECCA LOUISE SORRENTINO LETIZIA FRANCESCA SOSINSKI THOMAS JOHN SPARKS WADE ALAN SPITZNAGEL LAURA CAROL SPRACKLIN CHRISTINA ANN SPRENGER CRYSTAL-LEE SPRINGATE HILARY ROBERT DOUGLAS ST JOHN LORING PAULSEN STADLER MICHAEL MARKUS STANKIEWICZ WITOLD STEIN NICOLE JACQUELINE STEIN RAYMOND MARK STEINER BRIAN STEINHAUSER JACQUELINE MIRIAM STERN FLORENCE MARIE STERNS CYNTHIA SHAWN STEVENS ALAN PETER STEWART SAMANTHA JEANNE STIEDA ALEXANDER JOHANN HANS STIEGER DALIAH STIJOHANN ANNETTE MARIA ST-JEAN GENEVIEVE STOERTZ WILLIAM SWINNERTON STONE BOE CHAD STRATTON BARBARA ELIZABETH ANN STRAUB ROLF THOMAS STRAUGHAN ROBERT WILLIAM STREETER JEDD CHARLES STRICKER SANDRO BRIAN STURZENEGGER KEVIN THIERRY SUDAN SABINA SUESS LILLY SUKAMTO KARISA ANNE SVENDSEN JAIME JO SVOBODA CARL JOHN SWEET BRIAN DAVID SZAVA-KOVATS GEORGE HELMUT SZEKRENYES CHRISTINE NICOLE TAGG JAMES DOUGLAS TAGG JUNE ELLEN TAKEUCHI AYAKO JUDY TARDIN JACQUELINE CORNELIA PITTET TATE MELANIE LISA TAVES KENNETH EDWARD GORDON TAY DANIEL CHEE-CHUNG TAY JIREH JIE TAYLOR KELLI ANGELA CHRISTINE TAYLOR STEPHEN CRAUFURD TEBAY WILLIAM WARREN TEMI ASTI ANDAYANI TENENBAUM GARY JAY TENGER CATHERINE LOUISE TEO ABIGAIL HUI-WEN TEO MICHELLE THAELL COURTNEY CAROLINE THAELL ROBB HURLBURT THEMIG NEIL EDWIN THIO NANCY GIOK TAN THOLEN PAUL ARTHUR THOMA GARY LEE THOMASSIN ROMAN KURT THOMPSON CHARLES EDWARD THOMPSON MARK ALLAN THOMPSON TRACI LYNN THORNE SUSAN SCHULTZ THORNGATE WARREN BAYLEY THUNDERSTORM LYNNE THUNDERSTORM SHADOW FOX THUNDERSTORM TUNDRA LEAF TIMMONS KELCY TING STEPHEN DAVID TKACHYK BRIAN JOHN TODTMAN SARAH TOLIVER CAROL LESLIE TOMAN CAMILLA PAULA TOMAN SARA SCOTT TOMAN TIMOTHY JOSEPH TOTODA TAKESHI TRAUTMANN GARY THOMAS TREMBLAY LORRAINE TSAI JAMES C TSE JESSICA HAYES TSE THERESA Y. Y. TSENG SU CHEN HELENA CHIEN TSIEN JOSEPHINE PING N TSUI LAURA MAN YANG TULLIUS NIKOLAUS TUNG BORIS TURNER II CLAYTON MAURICE TWISS GILES CHRISTOPHER RONALD TYLER FRED UITTENBOSCH MARCEL RENE ULRICH ROBERT BRIAN ULRICH RUTH URBINA ANDREA VALOIS CAROL VAN DER AUWERA CHLOE ALLISON VAN DER HAMMEN ELEANOR STRANZEL KLEPEIS VAN LOOVEREN SONIA MARIA VAN MAELE BENOIT ANNE KRIS VANDERMEULEN CORAL ANN AMANDA VARDI SHARON VEGA ALICE GRACE CROKER VERWEIRE EILEEN THERESA VEST FRAUKE VETTER MARJORIE DORIS VLACHOS MAYA MELANIE VOLI MARY ANN MELANIA VOLLMAR JEFFREY NEIL voloshchuk vladimir mikhaylov VON CROY Anastasia Maria Irina PRINZESSIN VON EYE DONATA KAROLINA VON GIERKE KARIN J VON MEISS DAVID CHRISTIAN VON-HOLTEN DEAN VOSU TREVOR ANTHONY VYBIRAL MARIE-ASHLEY CARMEN WADDINGTON BROOKE VICTORIA WAEBER KAREN WAGNER CATHARINA JOHANNA WALLACE AMELIA ELIZABETH WALTER BENJAMIN WANG CAROL CHUNG-I WANG JOYCE CHRISTIE WANG TZU YAO WARD BELINDA MAY WEBB CHRISTOPHER JOHN WEBER CARMEN EILEEN WEBER RUTH JANELL WEINGARTEN JORDAN SAMUEL WEINGUNI PASCAL ANDRE WELCH FREDDY EDWIN WELLS WILLIAM ROBERT WENK ALINE JOANNE WERNER ALEXANDER THEODORE WERNER BEATRICE AURORE WESLEY DOMINIC TRIANTAFILLOS PAPADOPOULOS WEST KARLY NATASHA WHEATLEY ANN BRAUN WHITBECK NICHOLAS DILLON WHITE BARBARA LOUISE WHITE MARY THERESA WHITELAW LINNEA SARAH WHITINGER KATHLEEN ROSEMARY WHITINGER RALEIGH GEORGE WHITNEY CARL LINN WHITTON CAROLYN WIDEMAN LEOLA KATHLEEN VIVIAN WIEBE STEPHANIE ANN WIESENDANGER THOMAS HANS ULRICH WIGHAM LAUREN HOEFLICH WIGOD REBECCA WIJNVEEN EDWARD RAYMOND WILCOX KATHLEEN ANN WILES ANNE ELIZABETH WILES RICHARD NIGEL WILKINSON CRAIG WILLIAM WILLIAMS CECIL HAROLD WILLIAMS DAVID I WILLIAMS JONATHON SCOT WILLIAMS JR THOMAS KEVIN WILLIS LYNDA PAIGE WILSON CATHERINE ELIZABETH WILSON DAVID ALLAN WILSON IAN PATRICK JOSEPH WINFIELD MARLENE BLAUER WISHART CORA NORVADA WISKOTT ALEXA SEA LOUISE WITHAM LESLIE KAREN WONG DILYS YUET-MEI LEE WONG JANET MAE KEE WONG JOY HOI YAN WONG WAI KONG EDMAN WOOD EDWARD GREGORY WOOD IAN DOUGLAS HAMILTON WOOD KAREN DALE WOOD LAWRENCE EUGENE WOODALL LUNDY JANETTE ELIZABETH WOODWARD CHRISTEL ALMA WOOLNER ELISABETH WORSFOLD TREVOR CHARLES WRIGHT PATRICK STEFAN WU ELAINE YATCHISIN JR JOHN YATES HENRY PUGH YAU KING YEUNG YEO FARRAH MARILYNN YEUNG ALLEN TAK BUN YEUNG THEODORE TAT YON EUNG JAE YOSHIDA TAKAAKI YOUNG NANCY LYNN YU ARTHUR WAI TAO YU EDWARD SHIN-HO YU YEN CHIA YU YU YUEN LEONARD HSU ZANETTI INES MARIA ZANETTI DAELLENBACH ROSANNA ANITA ZEBROWSKI ANN MARIE ZHENG XIAOJUN DAVID ZOBRIST STEPHEN ROLF ZUGARO DARIO A GALLI ZURFLUH JOHN HENRY Dated: January 21, 2016. Maureen Manieri, Manager Classification Team 82413, Examinations Operations—Philadelphia Compliance Services.
    [FR Doc. 2016-02312 Filed 2-5-16; 8:45 am] BILLING CODE 4830-01-P
    DEPARTMENT OF VETERANS AFFAIRS [OMB Control No. 2900—NEW] Agency Information Collection (Evaluation of the Department of Veterans Affairs Mental Health Services); Activities Under OMB Review AGENCY:

    Veterans Health Administration, Department of Veterans Affairs.

    ACTION:

    Notice.

    SUMMARY:

    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.

    DATES:

    Written comments and recommendations on the proposed collection of information should be received on or before March 9, 2016.

    ADDRESSES:

    Submit written comments on the collection of information through www.Regulations.gov, or to Office of Information and Regulatory Affairs, Office of Management and Budget, Attn: VA Desk Officer; 725 17th St. NW., Washington, DC 20503 or sent through electronic mail to [email protected]. Please refer to “OMB Control No. 2900—NEW (Evaluation of the Department of Veterans Affairs Mental Health Services) in any correspondence. During the comment period, comments may be viewed online through the FDMS.

    FOR FURTHER INFORMATION CONTACT:

    Crystal Rennie, Enterprise Records Service (005R1B), Department of Veterans Affairs, 810 Vermont Avenue NW., Washington, DC 20420, (202) 632-7492 or email [email protected]. Please refer to “OMB Control No. 2900—NEW (Evaluation of the Department of Veterans Affairs Mental Health Services)” in any correspondence.

    SUPPLEMENTARY INFORMATION:

    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 Federal Register Notice with a 60-day comment period soliciting comments on this collection of information was published at 80 FR 43159 on July 21, 2015.

    Titles: Evaluation of the Department of Veterans Affairs Mental Health Services.

    OMB Control Number: 2900—NEW.

    Type of Review: New Collection Request.

    Abstract: This is a congressionally-mandated research study to evaluate mental health services provided by the VA. Congress directed the VA to conduct a survey of veterans with assistance from the Institute of Medicine (IOM) of the National Academies.

    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.

    Affected Public: Individuals or Households.

    Estimated Annual Burden: 5,192 burden hours.

    Estimated Average Burden per Respondent: 35 minutes.

    Frequency of Response: Annually.

    Estimated Number of Respondents: 8,900.

    By direction of the Secretary.

    Crystal Rennie, Department Clearance Officer, Department of Veterans Affairs.
    [FR Doc. 2016-02294 Filed 2-5-16; 8:45 am] BILLING CODE 8320-01-P
    81 25 Monday, February 8, 2016 Proposed Rules Part II Department of the Interior Bureau of Land Management 43 CFR Parts 3100, 3160, and 3170 Waste Prevention, Production Subject to Royalties, and Resource Conservation; Proposed Rule DEPARTMENT OF THE INTERIOR Bureau of Land Management 43 CFR Parts 3100, 3160, and 3170 [15X.LLWO300000.L13100000.NB0000] RIN 1004-AE14 Waste Prevention, Production Subject to Royalties, and Resource Conservation AGENCY:

    Bureau of Land Management, Interior.

    ACTION:

    Proposed rule.

    SUMMARY:

    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.

    DATES:

    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 Federal Register. Therefore, a comment to the OMB on the proposed information collection requirements is best assured of having its full effect if the OMB receives it by March 9, 2016.

    ADDRESSES:

    Mail: U.S. Department of the Interior, Director (630), Bureau of Land Management, Mail Stop 2134 LM, 1849 C St. NW., Washington, DC 20240, Attention: 1004-AE14. Personal or messenger delivery: 20 M Street SE., Room 2134LM, Washington, DC 20003. Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions at this Web site.

    Comments on the information collection burdens: Fax: Office of Management and Budget (OMB), Office of Information and Regulatory Affairs, Desk Officer for the Department of the Interior, fax 202-395-5806. Electronic mail: [email protected]. Please indicate “Attention: OMB Control Number 1004-XXXX,” regardless of the method used to submit comments on the information collection burdens. If you submit comments on the information collection burdens, you should provide the BLM with a copy, at one of the addresses shown earlier in this section, so that we can summarize all written comments and address them in the final rule preamble.

    FOR FURTHER INFORMATION CONTACT:

    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.

    SUPPLEMENTARY INFORMATION:

    I. Executive Summary A. Background

    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.1

    1 Office of Natural Resources Revenue (ONRR), Statistical Information, http://statistics.onrr.gov/ReportTool.aspx using Sales Year—FY2014—Federal Onshore—All States Sales Value and Revenue for Oil, NGL, and Gas products as of December 2, 2015.

    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.2

    2 The Energy Information Administration (EIA), Trends in U.S. Residential Natural Gas Consumption, http://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2010/ngtrendsresidcon/ngtrendsresidcon.pdf (reporting that in 2009, U.S. residential consumption was approximately 74 Mcf per household with natural gas service).

    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 surrounding areas through visual and noise impacts from flaring, and regional and global air pollution problems of smog, particulate matter, toxic air pollution (such as benzene, a carcinogen) and climate change. The primary constituent of natural gas is methane, and increases in gas wasted through venting, flaring or leaks contribute to increases in atmospheric methane levels. Methane is an especially powerful greenhouse gas (GHG), with climate impacts roughly 25 times those of CO2, if measured over a 100-year period, or 86 times those of CO2, if measured over a 20-year period.3 Thus, measures to conserve gas and avoid waste may significantly benefit local communities, public health, and the environment.

    3 See Intergovernmental Panel on Climate Change, Climate Change 2013: The Physical Science Basis, Chapter 8, Anthropogenic and Natural Radiative Forcing, at 714 (Table 8.7), available at https://www.ipcc.ch/pdf/assessment-report/ar5/wg1/WG1AR5_Chapter08_FINAL.pdf.

    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, 1909.4 In particular, the MLA requires the BLM to ensure that lessees “use all reasonable precautions to prevent waste of oil or gas developed in the land . . . .” 5 This proposal would replace current requirements related to flaring, venting, and royalty-free use of production, which are contained in NTL-4A; amend the BLM's oil and gas regulations at 43 CFR part 3160; and add new subparts 3178 and 3179. It would apply to all Federal and Indian (other than Osage Tribe) onshore oil and gas leases as well as leases and business agreements entered into by tribes (including IMDA agreements), as consistent with those agreements and with principles of Federal Indian law.6

    4 Mineral Leasing Act, 30 U.S.C. 188-287; Mineral Leasing Act for Acquired Lands, 30 U.S.C. 351-360; Federal Oil and Gas Royalty Management Act, 30 U.S.C. 1701-1758; Federal Land Policy and Management Act of 1976, 43 U.S.C. 1701-1785; Indian Mineral Leasing Act of 1938, 25 U.S.C. 396a-g; Indian Mineral Development Act of 1982, 25 U.S.C. 2101-2108; Act of March 3, 1909, 25 U.S.C. 396.

    5 30 U.S.C. 225.

    6 Key statutes underpinning this proposed regulation contain exceptions for the Osage Tribe. Specifically, the Osage Tribe is excepted from the application of both the Indian Mineral Leasing Act and the Federal Oil and Gas Royalty Management Act, 25 U.S.C. 396f; 43 U.S.C. 1702(3), 1702(4). The leasing of Osage Reservation lands for oil and gas mining is subject to special Bureau of Indian Affairs regulations contained in 43 CFR part 226.

    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,” 7 and identified concerns about royalty-free use of gas. These reports recommended that the BLM update its regulations to address waste prevention, afford flexibility in rate setting, and clarify policies regarding royalty-free, on-site use of oil and gas. With respect to waste, 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.” 8 The GAO recommended that the BLM reduce venting and flaring of gas by revising its regulations “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.” 9 The GAO further recommended that the BLM consider expanded use of infrared cameras to identify opportunities to minimize lost gas.10

    7 GAO, Oil and Gas Royalties: The Federal System for Collecting Oil and Gas Revenues Needs Comprehensive Reassessment, GAO-08-691, September 2008, 6.

    8 GAO, Federal Oil and Gas Leases: Opportunities Exist to Capture Vented and Flared Natural Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases, GAO-11-34, (Oct. 2010), 2.

    9 Ibid. at 34.

    10 Ibid. at 34.

    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 not less than 12.5 percent in amount or value of the production removed or sold from the lease.” 11 In addition, the proposed rule would update the BLM's existing NTL-4A requirements related to venting, flaring, and royalty-free use of natural gas from onshore Federal and Indian leases. Under NTL-4A, operators must apply to the BLM on a case-by-case basis for approval to flare royalty-free, based on economic criteria. We propose to reduce the need for case-by-case applications by clarifying when flared or vented natural gas is subject to royalties. Further, with respect to venting and flaring of natural gas, we propose to: Prohibit venting, except in certain limited circumstances; limit the rate of routine flaring at development oil wells; 12 require operators to detect and repair leaks; and mandate reductions in venting from: Pneumatic controllers and pneumatic pumps that operate by releasing natural gas; storage vessels; activities to unload liquids from a well; and well drilling, completion, and testing activities. Finally, the proposed rule would require operators to submit gas capture plans with their Applications for Permits to Drill new wells.

    11 30 U.S.C. 226(b)(1)(A) (emphasis added); see also 30 U.S.C. 352 (applying the MLA's leasing provisions to leases on acquired land).

    12 “Development oil well” or “development gas well” means a well drilled to produce oil or gas, respectively, from an established field in which hydrocarbons have been discovered and from which they are being produced at a profit or expected profit.

    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. 13 For each forum, we held a tribal outreach session in the morning and a public outreach session in the afternoon. We also accepted informal comments generated as a result of the public/tribal outreach sessions. Since those meetings, we have continued to consult with stakeholders throughout the rule development process, including numerous meetings and calls with State representatives, individual companies, trade associations, and non-governmental organizations (NGOs). We have also received and considered many reports, peer-reviewed studies, and letters from stakeholders providing information and views on what the BLM should propose.

    13 Further information can be found at the BLM oil and gas program's outreach-events page: http://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.html.

    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 venting from oil and gas production activities. Domestically, the Environmental Protection Agency (EPA) and a few individual States have been active in this area, as have some oil and gas producers. In 2012, for example, the EPA adopted Clean Air Act new source performance standards (NSPS) for certain activities in the oil and gas production sector. These regulations target reductions of volatile organic compounds (VOCs) and have the effect of reducing venting and leaks. The EPA recently proposed regulations to amend the 2012 NSPS for the oil and natural gas source category by setting standards for both methane and VOCs for certain equipment, processes and activities across this source category (40 CFR part 60 subpart OOOOa rulemaking).14 This EPA proposal would have the effect of further reducing gas losses through venting and leaks.

    14 EPA, Oil and Natural Gas Sector: Emission Standards for New and Modified Sources, Proposed Rule, 80 FR 56593 (Sept. 18, 2015). For further information about EPA's existing and proposed NSPS standards for this source category, see Section IV.I.3 of this preamble below.

    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.15 The Colorado regulations require operators to implement leak detection and repair (LDAR) programs, replace high-bleed pneumatic controllers with low-bleed pneumatic controllers, and control emissions from storage vessels, among other things. Wyoming has adopted similar comprehensive regulations that apply in the Upper Green River Basin, a “nonattainment area” where air quality does not meet national ozone standards adopted by the EPA under the Clean Air Act.16 North Dakota has also adopted an innovative program to phase down flaring by operators across the State, requiring 91 percent gas capture by 2020.17 Pennsylvania has issued guidance that exempts oil and gas facilities from certain air quality permitting requirements if they implement changes to reduce gas loss, such as developing an LDAR program, reducing VOC emissions from storage vessels, and limiting flaring activity.18

    15 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Sections XII, XVII, XVIII, available at https://www.colorado.gov/pacific/sites/default/files/5-CCR-1001-9_0.pdf.

    16 Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    17 North Dakota Industrial Commission Order 24665 Policy Guidance Version 102215, available at https://www.dmr.nd.gov/oilgas/GuidancePolicyNorthDakotaIndustrialCommissionorder24665.pdf.

    18 Pennsylvania Department of Environmental Protection, Air Quality Permit Exemptions (Aug. 10, 2013), available at http://www.elibrary.dep.state.pa.us/dsweb/Get/Document-96215/275-2101-003.pdf, at 8-11.

    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 2013.19 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.20 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.” 21

    19 EPA Natural Gas STAR Accomplishments, available at http://www3.epa.gov/gasstar/accomplishments/index.html.

    20 EPA Natural Gas Star Methane Challenge, Program Proposal, available at http://www3.epa.gov/gasstar/methanechallenge/index.html.

    21 Maria Galluci, Six Major Oil & Gas Firms Agree To Cut Potent Methane Emissions Ahead Of UN Climate Change Summit, International Business Times, Sept. 23, 2014, http://www.ibtimes.com/six-major-oil-gas-firms-agree-cut-potent-methane-emissions-ahead-un-climate-change-summit-1693517; http://www.gastechnology.org/CH4/Documents/Fiji-George-CH4-presentation-Sep2014.pdf; One Future: Our Nation's Energy, 1, 6 (Sept. 2014), http://www.gastechnology.org/CH4/Documents/Fiji-George-CH4-presentation-Sep2014.pdf.

    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 and cost savings using a 3 percent discount rate).22

    22 BLM, Economic Impact and Regulatory Threshold Analysis for 43 CFR 3178 (Royalty Free Use of Production) and 43 CFR 3179 (Venting and Flaring Requirements) (2015) (hereinafter RIA) at 7.

    B. Summary of Proposal

    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.

    1. Venting and Flaring

    In 2013, operators vented about 22 Bcf and flared at least 76 Bcf of natural gas from BLM-administered leases.23 The 2013 flaring estimate, a 109 percent increase from 2009 levels,24 represents 2.6 percent of the total production from BLM-administered leases in that year (2,901 Bcf) 25 and sufficient gas to supply over 1 million households.26 Of this, roughly 71 Bcf came from oil wells.27 Analysis of data supplied by the ONRR suggests that most of this was routine flaring of associated gas from development oil wells (as opposed to flaring during exploration, well testing, and emergencies). Over 90 percent of this flaring occurred in North Dakota, South Dakota, and New Mexico.28

    23 RIA at 119-120.

    24 RIA 119.

    25 RIA at 111 (Appendix A-2).

    26 See footnote 2 (assuming 2009 usage levels).

    27 RIA at 33.

    28 RIA at 122 (Appendix A-8, Table 4).

    The BLM is proposing to prohibit venting of natural gas, except under certain conditions, including in emergencies, as would be defined in the regulations.29 With respect to flaring, the BLM proposes to limit the rate of routine flaring of associated gas from development oil wells and retain the current exemptions from gas capture requirements and royalties for gas flared in other situations, as long as the operator has complied with the proposed requirements to minimize such losses. These exemptions include gas lost in the normal course of well drilling and well completion; well tests; emergencies, as would be defined in the regulations; 30 and gas flared from exploration or wildcat wells, or delineation wells (wells drilled to define the boundaries of a mineral deposit).

    29 See proposed 43 CFR 3179.105.

    30 Ibid.

    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.31 The BLM estimates that this limit would reduce flaring by up to 74 percent, although there is substantial uncertainty regarding this estimate. The BLM proposes to retain the authority to allow higher rates of flaring in specific circumstances, where adhering to the proposed flaring limit 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. Further, the BLM proposes to create a 2-year renewable exemption from the flaring limit, available only for certain existing leases that are located a significant distance from gas processing facilities and flaring at a rate well above the proposed flaring limit. Holders of these leases have, until now, had no prior notice of the proposed flaring limit. Given the significant distance from these leases to the nearest gas capture facilities, and the leases' high rates of gas flaring, operators at these sites might have few options to meet the proposed flaring limit other than shutting in the wells. The BLM anticipates the number of leases eligible for this 2-year exemption would decline over time, as production of oil and associated gas from existing leases naturally declines.

    31 Wyoming Operational Rules, Drilling Rules Section Ch. 3, Section 39(b), available at http://soswy.state.wy.us/Rules/RULES/9584.pdf (60 Mcf/day); Utah R649-3-20, Gas Flaring or Venting Section 1.1, available at (http://www.rules.utah.gov/publicat/code/r649/r649-003.htm#T20 (1,800 Mcf/mo.).

    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.32

    32 RIA at 69.

    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,” https://www.whitehouse.gov/omb/circulars_a094/, directs agencies to conduct baseline analyses using a discount rate of 7%, which “approximates the marginal pretax rate of return on an average investment in the private sector in recent years.” It also recommends that agencies show sensitivity of the discounted net present value and other outcomes using additional discount rates. The BLM chose to use a second discount rate of 3%, because the literature suggests that there is a divergence between private discount rates (considered by firms or industry) and social discount rates (considered by society), with private rates exceeding social rates. Further, it is common for regulatory impact analyses to analyze outcomes using a 3% discount rate, particularly for the environmental benefits of proposed regulations.

    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).33

    33 RIA at 60.

    2. Leaks

    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.34 Multiple studies have found that once leaks are detected, the vast majority can be repaired with a positive return to the operator. In addition, both Colorado and Wyoming (for part of the State) have recently adopted LDAR requirements for oil and gas production,35 and EPA has adopted and proposed additional LDAR requirements for certain new and modified oil and gas production sources.36

    34 RIA at 3.

    35 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.F; Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(g) (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    36 Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution, 60 CFR subpart OOOO; 80 CFR 56593, 56660-56698.

    The BLM believes that LDAR programs are a cost-effective means of reducing waste in oil and gas production. We are proposing to require operators to use an instrument-based approach to leak detection. Operators would be required initially to conduct semi-annual inspections at their well sites and compressor locations. If an operator finds no more than 2 leaks at a facility for two consecutive inspections, the operator may change to annual inspections at that facility. If the operator finds more than 2 leaks at a facility for two consecutive inspections, the operator must inspect for leaks quarterly. If an operator that is required to inspect for leaks quarterly finds no more than 2 leaks at a given facility in two sequential inspections, the operator could then change back to semi-annual inspections, and so forth. Once a leak is identified, the BLM proposes that the operator would be required to repair the leak as soon as practicable, but no later than 15 calendar days after discovery, absent good cause. Operators would have to verify the effectiveness of a repair within 15 calendar days of the repair, using the same method used to detect the leak. Operators would also be required to keep records documenting the dates and results of leak inspections, repairs, and follow-up inspections.

    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,37 then the BLM expects that its proposed requirements would impact 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 tons per year (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 2026.38

    37 The RIA includes a broader discussion of the estimates of the costs and benefits of this proposed rule if the EPA does not finalize its 40 CFR part 60 subpart OOOOa rulemaking, but the preamble omits some of those estimates to simplify the discussion. EPA's proposed requirements would apply to wells that are new, “modified,” or “reconstructed” after September 18, 2015. See 40 CFR 60.14 and 60.15 for EPA's definitions of “modification” and “reconstruction.”

    38 RIA at 109.

    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 2026.39

    39 RIA at 108-109.

    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.

    3. Pneumatic Controllers and Pneumatic Pumps

    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.40 Further, we estimate that the proposed rule would impact up to 15,600 high bleed pneumatic controllers (pneumatic controllers with bleed rates of more than 6 standard cubic feet per hour (scf/hour)) on BLM-administered leases.41 A recent study by the consulting firm ICF International (ICF) identified replacement of high-bleed pneumatic controllers with low-bleed pneumatic controllers (pneumatic controllers with bleed rates of 6 scf/hour or less) as one of the most inexpensive options for reducing methane, estimating that it would actually save industry $2.65 per Mcf of avoided methane emissions.42

    40 RIA at 3.

    41 RIA at 78.

    42 ICF International, Economic Analysis of Methane Emission Reduction Opportunities in the U.S. in the Onshore Oil and Natural Gas Industries, 4-4 (Mar. 2014), available at https://www.edf.org/sites/default/files/methane_cost_curve_report.pdf (ICF 2014 Study) (base case assumed $4/Mcf price for recovered gas and a 10 percent discount rate/cost of capital).

    EPA generally prohibits the use of new high-bleed pneumatic controllers,43 and Colorado and Wyoming (in part of the State) have required replacement of existing high-bleed pneumatic controllers with low-bleed pneumatic controllers.44 The State of Wyoming has 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, 2017.45

    43 40 CFR 60.5390.

    44 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVIII; Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(f) (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    45 Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(e) (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    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 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 of $53-68 million per year (using a 7 percent discount rate for costs and cost savings) or net benefits of $54-73 million per year (using a 3 percent discount rate for costs and cost savings), along with a reduction in VOC emissions of about 200,000 tpy.46

    46 Regulatory Impact Analysis (RIA) at 78.

    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.47

    47 RIA at 82.

    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.48

    48 RIA at 81.

    4. Storage Vessels

    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.49 Of that volume, we estimate that 1.82 Bcf was lost from storage vessels used in natural gas production and 0.95 Bcf of gas was lost from storage vessels used in oil production.50

    49 RIA at 3.

    50 RIA at 19.

    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.51

    51 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Sections XII.D-F; XVII.C; Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(c) (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    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 all hydrocarbons from vessels, not just loss of VOCs, we propose to use VOCs as a proxy for whole gas, and thus to apply the control requirement to existing vessels with at least 6 tpy of VOCs, using the same applicability threshold as EPA and Colorado.52 (Wyoming also uses VOC emissions to determine applicability, but has a lower threshold.53 )

    52 40 CFR 60.5395; Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.C.

    53 Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(c)(i)(a) (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    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, these requirements would no longer apply if the uncontrolled VOC emissions fall below 4 tpy for 12 months.

    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).54 We project that these requirements would increase gas production by 0.04 Bcf per year, resulting in cost savings of about $0.1-0.2 million per year (using 7 percent and 3 percent discount rates). They would also reduce methane emissions by 7,000 tpy, producing monetized benefits of $8 million per year in 2017-2019, $9 million per year in 2020-2024, and $11 million in 2025 and 2026. Overall, we estimate that these provisions would result in net benefits of $2 million per year in 2017-2019, $3-4 million per year in 2020-2024, and $5 million in 2025 and 2026, and reduce VOC emissions by 32,500 tpy.

    54 RIA at 95.

    5. Well Maintenance and Liquids Unloading

    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.55

    55 RIA at 3.

    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.56

    56 RIA at 87.

    6. Reduction of Waste From Drilling, Completion, and Related Operations

    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.57 Of this, we estimate that completion emissions from hydraulically fractured (and refractured) oil wells accounted for 1.4 Bcf of the loss, emissions from hydraulically fractured gas wells accounted for about 0.7 Bcf of the loss, and all other completions accounted for a de minimis amount.58

    57 RIA at 3.

    58 RIA at 18 (Table 6).

    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 hydraulically fractured oil wells, as EPA already covers hydraulically fractured gas wells.

    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 de minimis anticipated incremental production, incremental royalty, and emissions reductions.59

    59 RIA at 74.

    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.60

    60 RIA at 74.

    7. Royalty Provisions Governing New Competitive Leases

    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 61 for all noncompetitive leases issued after the effective date of the rule; and (3) Make the rule text parallel to the corresponding MLA text for competitive leases issued after the effective date of the rule.62 The MLA text provides the BLM the flexibility to set royalty rates for these competitive leases at or above 12.5 percent. By contrast, the BLM's existing royalty regulation sets a flat rate of 12.5 percent for all new competitive leases.63 Although the BLM does not currently propose to raise royalty rates, the proposed rule would allow the BLM to set a royalty rate for oil and gas produced from competitive oil and gas leases issued after the effective date of this rule of “not less than” 12.5 percent. The BLM is not proposing any further changes to the royalty provisions governing new competitive oil and gas wells,64 but we are requesting comment on the use of a fluctuating royalty rate to incentivize reductions in flaring from new competitive leases. Further information about this possible approach is provided below in Section V.C. of this preamble.

    61 30 U.S.C. 226(c)(1).

    62 30 U.S.C. 226(b)(1)(A).

    63 43 CFR 3103.3-1(a)(1).

    64 Note that the proposed rule would renumber current 43 CFR 3103.3-1 (a)(2) and (3) but would not otherwise change the content of those provisions. Further, the proposed rule would not alter 43 CFR 3103.3-1(b), (c), or (d). Those five provisions are reprinted in this proposed rule solely to clarify the proposed numbering of the revised § 3103.3-1, and for ease of reference. The BLM does not intend to revise those provisions, nor to invite comment on their content.

    C. Summary of Costs and Benefits 1. Costs

    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.65 These costs would include engineering compliance costs and the social cost of minor additions of carbon dioxide to the atmosphere, resulting from the on-site or downstream use of gas that is newly captured as a result of this proposed rule.66 The engineering compliance costs presented do not include potential cost savings from the recovery and sale of natural gas (those savings are shown in the summary of benefits).

    65 RIA at 127.

    66 Some gas that would have otherwise been vented would now be combusted on-site or presumably downstream to generate electricity. As described in the RIA, the estimated value of these carbon additions would not exceed $30,000 in any given year.

    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.67

    67 RIA at 127.

    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 2020.68

    68 RIA at 159. These estimates rely on 2014 company data, use a 7% discount rate, and assume the finalization of EPA's 40 CFR part 60 subpart OOOOa rulemaking.

    2. Benefits

    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).69 We estimate that the proposed rule would reduce methane emissions by 164,000-169,000 tpy, which we estimate to be worth $180-253 million per year (this social benefit is included in the monetized benefit above). We estimate that the proposed rule would reduce VOC emissions by 391,000-411,000 tpy (this benefit is not monetized in our calculations).70

    69 RIA at 130.

    70 RIA at 133-135.

    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).71 We estimate that the proposed rule would reduce methane emissions by 176,000-185,000 tpy, which we estimate to be worth $193-277 million per year (this social benefit is included in the monetized benefit above). We estimate that the proposed rule would reduce VOC emissions by 400,000-423,000 tpy (this benefit is not monetized in our calculations).72

    71 RIA at 130.

    72 RIA at 133-135.

    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 (NOX) and particulate matter, which can cause respiratory and heart problems.

    3. Net Benefits

    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 2025-2026.73

    73 RIA at 7.

    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).

    4. Influence on Production

    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 2013.74

    74 RIA at 140.

    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 2013.75

    75 RIA at 140.

    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.

    5. Royalties

    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).76 If, for purposes of analysis, we assume that the EPA does not finalize the 40 CFR part 60 subpart OOOOa rulemaking, we estimate that this proposed rule would result in annual incremental royalties of $9-11 million per year (discounted at 7 percent) or $11-17 million per year (discounted at 3 percent).

    76 RIA at 143.

    II. Table of Contents I. Executive Summary A. Background B. Summary of Proposal 1. Venting and Flaring 2. Leaks 3. Pneumatic Controllers and Pneumatic Pumps 4. Storage Vessels 5. Well Maintenance and Liquids Unloading 6. Reduction of Waste From Drilling, Completion, and Related Operations 7. Royalty Provisions Governing New Competitive Leases C. Summary of Costs and Benefits 1. Costs 2. Benefits 3. Net Benefits 4. Royalties II. Table of Contents III. Public Comment Procedures IV. Background A. Overview B. Impacts of Waste and Loss of Gas C. Purpose of This Rule D. Stakeholder Outreach E. Existing BLM Regulations and Requirements for Preventing Natural-Gas Waste F. Legal Authority G. Concerns About Loss of Gas Identified Through Oversight H. Volumes of Lost Natural Gas 1. Data Sources on Lost Gas 2. Additional Information on Loss Estimates I. Examples of and Gaps in Existing Waste-Reduction and Related Efforts 1. State Activities 2. Voluntary Industry Efforts 3. EPA Air Quality Requirements V. Discussion of the Proposed Rule A. Measures To Reduce Waste 1. Venting or Flaring of Associated Gas From Producing Oil Wells 2. Leaks 3. Pneumatic Controllers and Pneumatic Pumps 4. Storage Vessels 5. Well Maintenance and Liquids Unloading 6. Reduction of Waste From Drilling, Completion, and Related Operations 7. Additional Opportunities To Reduce Waste From Venting B. Royalty-Free Use of Production C. Royalty Rates on New Competitive Leases D. Record Keeping Requirements E. Reporting and Information Availability F. Planning Process G. Facilities in Rights-of-Way H. State or Tribal Variances I. Section-by-Section Discussion 1. Section 3103.3-1 2. Section 3160.0-5 3. Section 3162.3-1 4. Subpart 3178—Royalty-Free Use of Lease Production 5. Subpart 3179—Waste Prevention and Resource Conservation 6. Flaring and Venting Gas During Drilling and Production Operations 7. Gas Flared or Vented From Equipment or During Well Maintenance Operations 8. Leak Detection and Repair 9. State or Tribal Variances VI. Analysis of Impacts A. Description of the Regulated Entities 1. Potentially Affected Entities 2. Affected Small Entities B. Impacts of the Proposed Requirements 1. Overall Costs of the Rule 2. Overall Benefits of the Rule 3. Net Benefits of the Rule 4. Distributional Impacts VII. Procedural Matters A. Executive Order 12866, Regulatory Planning and Review B. Regulatory Flexibility Act and Small Business Regulatory Enforcement Fairness Act of 1996 C. Unfunded Mandates Reform Act of 1995 D. Executive Order 12630, Governmental Actions and Interference With Constitutionally Protected Property Rights (Takings) E. Executive Order 13132, Federalism F. Executive Order 12988, Civil Justice Reform G. Executive Order 13175, Consultation and Coordination With Indian Tribal Governments H. Paperwork Reduction Act 1. Overview 2. Summary of Proposed Information Collection Requirements 3. Proposals Involving APDs and Sundry Notices 4. Other Proposed Information Collection Activities 5. Burden Estimates I. National Environmental Policy Act J. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use K. Clarity of the Regulations L. Executive Order 13563, Improving Regulation and Regulatory Review VIII. Authors III. Public Comment Procedures

    If you wish to comment on the proposed rule, you may submit your comments by any one of several methods specified (see ADDRESSES). If you wish to comment on the information collection requirements, you should send those comments directly to the OMB as outlined (see ADDRESSES); however, we ask that you also provide a copy of those comments to the BLM.

    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 DATES) or comments delivered to an address other than those listed (see ADDRESSES).

    Comments, including names and street addresses of respondents, will be available for public review at the address listed under ADDRESSES during regular hours (7:45 a.m. to 4:15 p.m.), Monday through Friday, except holidays. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.

    IV. Background A. Overview

    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.77

    77 ONRR, Statistical Information, http://statistics.onrr.gov/ReportTool.aspx using Sales Year—FY2014—Federal Onshore—All States Sales Value and Revenue for Oil, NGL, and Gas products as of December 2, 2015.

    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.78

    78 Based on an estimate of 74 Mcf of gas used per household per year. See footnote 2.

    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.79 This represents about 3.4 percent of the total production from BLM-administered leases in that year (2,901 Bcf).80

    79 RIA at 3.

    80 RIA at 111 (Appendix A-2).

    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 related to venting, flaring, and royalty-free use of natural gas, which are over 3 decades old. The BLM proposes to clarify the circumstances under which operators may flare, or in very limited circumstances vent, natural gas produced in the course of exploration, development, and production activities, and we propose to expand the circumstances under which flared or vented natural gas would be subject to royalties. The BLM also proposes other reasonable measures to reduce wasteful venting, flaring, and leaks of natural gas from oil and gas operations on Federal and Indian leases.

    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.

    B. Impacts of Waste and Loss of Gas

    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.81

    81 RIA at 3.

    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 NOX, which are created by burning fossil fuels, to form ground-level ozone, or smog, which causes a wide range of health effects. Benzene and other components of natural gas are also classified as hazardous air pollutants, which are known or suspected to cause cancer or reproductive effects.82 Flaring of gas produces NOX and particulate matter, both of which can cause respiratory and heart problems.83

    82 The EPA has classified benzene as a known human carcinogen and reproductive effects have been reported at high exposures and observed in animal studies. U.S. EPA, Benzene Hazard Summary (online at: http://www3.epa.gov/airtoxics/hlthef/benzene.html).

    83 U.S. EPA, Nitrogen Dioxide; Health (online at: http://www3.epa.gov/airquality/nitrogenoxides/health.html); U.S. EPA, Particulate Matter; Health (online at: http://www3.epa.gov/pm/health.html).

    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 CO2, on a ton-per-ton basis. Over a 20-year time-frame, methane is 86 times more potent than CO2, according to the most recent report of the Intergovernmental Panel on Climate Change.84 Venting, flaring, and leaks also produce CO2. As the President's Climate Action Plan recognizes, reducing methane emissions can make an important contribution to addressing climate change.85

    84 See Intergovernmental Panel on Climate Change, Climate Change 2013: The Physical Science Basis, Chapter 8, Anthropogenic and Natural Radiative Forcing, at 714 (Table 8.7), available at https://www.ipcc.ch/pdf/assessment-report/ar5/wg1/WG1AR5_Chapter08_FINAL.pdf.

    85 The President's Climate Action Plan, https://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf. at 10-11 (June 2013)

    C. Purpose of This Proposed Rule

    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,86 pertaining to venting and flaring, unavoidably and avoidably lost gas, and waste prevention. The proposed rule would ensure that operators use best practices that minimize waste from new and existing operations.

    86 44 FR 76600 (1979). The U.S. Geological Survey (USGS) issued regulations on these subjects in NTL-4A. In the early 1980's, the responsibility for Federal onshore oil and gas operations was transferred from the USGS to the Minerals Management Service (MMS). In 1983, the Secretary transferred the responsibility to the BLM. NTL-4A has remained in force through the changes in agency responsibility.

    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.

    D. Stakeholder Outreach

    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, 2014), Dickinson, North Dakota (May 9, 2014), and Washington, DC (May 14, 2014).87 Each day, we held a tribal outreach session in the morning and a public outreach session in the afternoon. At the Denver, Colorado, and Washington, DC sessions, the tribal and public meetings were live streamed to allow for the greatest possible participation by interested parties. The tribal outreach sessions also served as initial consultation with Indian tribes to comply with Executive Order 13175, Consultation and Coordination with Indian tribal governments.

    87 See the BLM oil and gas program's outreach-events page: http://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.

    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.

    E. Existing BLM Regulations and Requirements for Preventing Natural-Gas Waste

    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.” 88 Both prohibitions are subject to specified exemptions for emergencies, certain equipment malfunctions, certain well tests, and vapors from storage vessels. With respect to venting or flaring of oil well gas, NTL-4A IV.B states:

    88 44 FR 76600. (Dec. 27, 1979).

    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.89

    89 Ibid.

    Thus, the key criteria under this provision in NTL-4A for approving venting or flaring (and rendering it royalty-free) are: (1) That the expenditures for capture are “not economically justified,” and they would “lead to the premature abandonment of recoverable oil reserves”; or (2) The venting or flaring will be eliminated within 1 year.90 NTL-4A IV.C also provides that “(w)hen evaluating the feasibility of requiring conservation of the gas, the total leasehold production, including both oil and gas, as well as the economics of a field wide plan shall be considered . . . in determining whether the lease can be operated successfully if it is required that the gas be conserved.” 91

    90 Ibid.

    91 Ibid.

    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.” 92 NTL-4A I further provides that no royalty is due for gas that is: (1) Used on the lease for “beneficial purposes”; (2) Vented or flared with the Supervisor's prior authorization or approval; (3) Vented or flared pursuant to State rules or orders, when such rules have been ratified or accepted by the Supervisor; or (4) Otherwise unavoidably lost, as determined by the Supervisor.93

    92 44 FR at 76600. (Dec. 27, 1979).

    93 Ibid.

    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.94 Venting or flaring is authorized during emergency situations, such as equipment failures, for up to 24 hours per incident and up to 144 cumulative hours per lease per month.95 NTL-4A III.B. authorizes venting or flaring “(d)uring the unloading or cleaning up of a well during drillstem, producing, routine purging, or evaluation tests, not exceeding a period of 24 hours.” 96 In addition, NTL-4A III.C. authorizes venting or flaring during initial well evaluation tests, for up to 30 days or up to 50 million cubic feet (MMcf) of gas, whichever occurs first.97 Finally, NTL-4A II.C. provides that gas vapors that are released from storage tanks or other low-pressure vessels are considered to be unavoidably lost, and not subject to royalties, unless the Supervisor determines that their recovery is warranted.98

    94 Ibid.

    95 Ibid.

    96 Ibid.

    97 Ibid.

    98 Ibid.

    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.99 This provision was subsequently overridden, however, by the later-enacted FOGRMA.100 Section 308 of FOGRMA states, “Any lessee is liable for royalty payments on oil or gas lost or wasted from a lease site when such loss or waste is due to negligence on the part of the operator of the lease, or due to the failure to comply with any rule or regulation, order or citation issued under this Act or any mineral leasing law.” 101

    99 Ibid.

    100 30 U.S.C. 1701 et seq.

    101 30 U.S.C. 1756.

    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.

    F. Legal Authority

    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, 1909.102

    102 See footnote 4.

    The MLA rests on the fundamental principle that the public should benefit from mineral production on public lands.103 A primary instrument for public benefit is the requirement that a lessee return a portion of the proceeds from production to the public through the payment of royalties to Federal, State, and tribal governments. For all competitively issued leases on Federal lands, the MLA requires a royalty “at a rate of not less than 12.5 percent in amount or value of the production removed or sold from the lease.” 104 The BLM is responsible for setting royalty rates and determining the quantity of produced oil and gas that is subject to royalties under the terms and conditions of a Federal lease. The MLA also requires the BLM to: Ensure that lessees “use all reasonable precautions to prevent waste of oil or gas developed in the land”; 105 regulate “all surface-disturbing activities conducted pursuant to any lease issued under (the MLA)”; 106 and “determine reclamation and other actions as required in the interest of conservation of surface resources.” 107

    103See, e.g., California Co. v. Udall, 296 F.2d 384, 388 (D.C. Cir. 1961) (noting that the MLA was “intended to promote wise development of . . . natural resources and to obtain for the public a reasonable financial return on assets that `belong' to the public”). The Indian Mineral Leasing Act also had the similar purpose of securing for Indian tribes “the greatest return on their property.” Kerr-McGee v. Navajo Tribe of Indians, 731 F.2d 597, 601 n.3 (internal quotation mark omitted).

    104 30 U.S.C. 226(b)(1)(A) and (c)(1); 30 U.S.C. 352 (applying that requirement to leases on acquired land). The same royalty provision is included in the lease instruments for leases of Indian tribal and allotted lands under applicable regulations, although that rate is set at no less than 16-2/3%, absent approval of the Secretary. 25 CFR 211.41, 212.41.

    105 30 U.S.C. 225.

    106 30 U.S.C. 226(g).

    107 Ibid.

    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.” 108 In addition, the BLM is required to manage public lands under principles of multiple use and sustained yield under FLPMA, which include management of the lands without permanent impairment of the quality of the environment.109 The definition of “multiple use” explicitly includes the consideration of environmental resources; “multiple use” means a “combination of balanced and diverse resource uses that takes into account the long-term needs of future generations for renewable and nonrenewable resources, including, but not limited to, recreation, range, timber, minerals, watershed, wildlife and fish, and natural scenic, scientific, and historical values.” 110 Further, the statutory definition of “multiple use” constitutes management in a “harmonious and coordinated” manner “without permanent impairment to the productivity of the land and the quality of the environment.” 111 Significantly, FLPMA admonishes the Secretary to consider “the relative values of the resources and not necessarily . . . the combination of uses that will give the greatest economic return of the greatest unit output.” 112 FLPMA also mandates that the Secretary, “(i)n managing the public lands . . . shall, by regulation or otherwise, take any action necessary to prevent unnecessary or undue degradation of the lands.” 113

    108 Ibid. 1701(a)(8).

    109 43 U.S.C. 1702(c), 1732(a).

    110 Ibid. (emphasis added).

    111 Ibid. (emphasis added).

    112 Ibid.

    113 Ibid. 1732(b).

    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 production removed or sold from the lease.” 114 As established in several judicial decisions, the phrase “production removed or sold from the lease” exempts from royalty payments production that is used on the lease for lease operations.115 Thus, operators may use oil or gas on the lease royalty-free to support the productivity of the lease. For example, a lessee may use produced gas to power the production infrastructure.

    114 30 U.S.C. 226(b)(1)(A) (emphasis added).

    115See Marathon Oil Co. v. Andrus, 452 F. Supp. 548, 522-23 (D. Wyo. 1978); Gulf Oil Corp. v. Andrus, 460 F. Supp. 15, 18 (C.D. Cal. 1978).

    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.116 Under NTL-4A, in determining when production is unavoidably versus avoidably lost, the BLM has generally considered the technical and economic feasibility of preventing the loss of gas. Under NTL-4A, the BLM deems a loss of gas “avoidable”—and charges associated royalties—if it determines that such loss occurred as a result of: (1) Negligence on the part of the lessee or operator; (2) The failure of the lessee or operator to take all reasonable measures to prevent and/or to control the loss; and/or (3) The failure of the lessee or operator to comply fully with the applicable lease terms and regulations, appropriate provisions of the approved operating plan, or the prior written orders of the BLM.117 If, on the other hand, the loss of gas is not the result of operator negligence and results from certain specified circumstances, such as emergencies, well tests, and production tests, or if the BLM determines that venting from storage tanks is “warranted,” the BLM deems the loss “unavoidable” and does not charge associated royalties.118 As discussed below, however, the BLM has not always been consistent in applying this distinction between “unavoidably” and “avoidably” lost gas, creating significant confusion for both operators and regulators. The proposed rule seeks to clarify the distinction, and thereby limit the need for operators to submit, and BLM to process, applications for approval of royalty-free use of gas.

    116 44 FR 76600.

    117 Ibid.

    118 Ibid. at 76,601.

    G. Concerns About Loss of Gas Identified Through Oversight

    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, Mineral Revenue Collection from Federal and Indian Lands and the Outer Continental Shelf, includes specific recommendations to the BLM and the former Minerals Management Service (MMS (which was subsequently divided into ONRR, the Bureau of Ocean Energy Management (BOEM), and the Bureau of Safety and Environmental Enforcement.)) The report emphasized the need for enhanced verification of production accountability, and it recommended that the BLM update relevant pre-1983 (remnant U.S. Geological Survey and MMS) rules. In recognition of those needs, the BLM began a process to implement the recommendations to improve production accountability oversight. This proposed rule—along with other separately proposed rules dealing with site security and oil and gas measurement—responds to recommendations in the RPC's report. A March 2010 report by the Department of the Interior Inspector General also recommended that the BLM clarify its requirements for royalty-free use of gas.119

    119 Department of the Interior, Inspector General, BLM and MMS Beneficial Use Deductions (March 2010), https://www.doioig.gov/sites/doioig.gov/files/2010-I-00171.pdf.

    In October 2010, the GAO issued a report entitled, Federal Oil and Gas Leases—Opportunities Exist to Capture Vented and Flared Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases. For this audit, the GAO examined the amounts of natural gas being vented and flared on Federal oil and gas leases, and evaluated the potential for additional capture of natural gas using available technologies. The GAO also evaluated what the associated potential increases in royalty payments and decreases in GHG emissions would be from any additional gas capture.

    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.” 120 The GAO further found that “Interior's oversight efforts to minimize these losses have several limitations, including that its regulations and guidance do not address” new capture technologies and some significant sources of lost gas.121 As the GAO noted, BLM guidance is over 30 years old and does not address venting and flaring reduction technologies that have advanced since it was issued, such as automated plunger lift technologies that reduce the amount of gas vented during liquid unloading operations or low-bleed pneumatic devices that can replace the functions of high-bleed pneumatic devices.122

    120 GAO-11-34, Oct. 2010, 2.

    121 Ibid. at 34.

    122 Ibid. at 27.

    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.”123 The GAO further recommended that the BLM should “assess the potential use of venting and flaring reduction technologies to minimize the waste of natural gas” before production occurs, and that the BLM should consider expanded use of infrared cameras to improve reporting and identify opportunities to minimize lost gas.124 This proposed regulation responds to these recommendations as well.

    123 Ibid. at 34.

    124 Ibid. at 34.

    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.125

    125 See discussion in Section I.1 of this preamble.

    H. Volumes of Lost Natural Gas 1. Data Sources on Lost Gas

    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, Onshore Petroleum and Natural Gas Operations on Federal and Tribal Lands in the United States. 126 With respect to oil and gas production, some of these sources estimate releases of natural gas, while others estimate methane emissions. Natural gas is primarily composed of methane, however, and translating back and forth between the two types of estimates is a relatively straightforward calculation.

    126 ICF, Onshore Petroleum and Natural Gas Operations on Federal and Tribal Lands in the United States (June 2015) (SHORT FORM—ICF 2015).

    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.”127

    127 GAO-11-34, Oct. 2010.

    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.128 These data are reported by operators on BLM-administered leases, but the production is actually derived from lands with various ownership patterns. Of the vented and flared gas reported to ONRR, 15.2 percent came from wells extracting only Federal minerals; 9.0 percent from Indian ownership, and 75.8 percent from mixed ownership (some combination of Federal, Indian, fee (private) and State land). While all of the natural gas flared or vented from the Federal and Indian lands categories originates from the Federal and Indian mineral estates, only a portion of the natural gas flared or vented from the mixed ownership category originates from the Federal and Indian mineral estates.

    128 Using U.S. Census Bureau Total Households as of 2013 (latest data available).

    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.129 Because we expect the national emissions level to be generally representative of what we would expect on Federal and Indian lands, we derived emissions estimates largely by applying the Federal and Indian share of production to the national emissions estimate.130 The analysis of these data sources indicates that roughly 22 Bcf of natural gas was lost from BLM-administered leases through venting and leaks in 2013.

    129 Based on updated EIA production crossed against ONRR Federal production data.

    130 For additional detail on these calculations, see RIA App. 7.

    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).131

    131 RIA at 19.

    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 2013,132 of which 66 Bcf originated from the Federal and Indian mineral estates.133 The 66 Bcf of vented or flared gas represents about 2.3 percent of total Federal and Indian production from these leases in 2013, and is enough gas to supply almost 900,000 homes each year.134 This is consistent with ICF's estimate that fugitive sources, vented emissions and flared emissions from Federal and Indian onshore leases amounted to 66 Bcf of natural gas in 2013.

    132 That is, 22 Bcf vented or leaked (per EPA GHG Inventory data), and 76 Bcf flared (per ONRR data).

    133 RIA at 3.

    134 Based on an estimate of 74 Mcf of gas used per household per year. See footnote 2.

    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 2013.135 During this period, reported volumes of flared oil-well gas increased by 292 percent, while reported volumes of flared gas-well gas decreased by 75 percent.136 The reduction in flaring at gas wells coincides with the adoption of EPA air pollution requirements limiting emissions from gas wells hydraulically fractured after August 2011.

    135 RIA at 201.

    136 Ibid.

    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.137

    137 BLM data extracted from AFMSS in response to media inquiry, October 2014.

    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, Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries, issued in March 2014. The ICF Study estimated methane emissions from onshore oil and gas production in 2018 based on a 2011 baseline. It found that absent regulation, emissions are projected to grow 4.5 percent from 2011 through 2018, and almost 90 percent of emissions in 2018 would come from sources that were already operating prior to 2012.138 Based on this information, the BLM believes that it is important for the proposal to address waste from both new sources and sources that already exist at the time of the final rule.

    138 ICF 2014 Study.

    2. Additional Information on Loss Estimates

    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 (e.g., EPA's Greenhouse Gas Reporting Program data and many of the series of studies being conducted by the Environmental Defense Fund, academic researchers, and industry, discussed below), and “top down” studies that focus on verification of estimates at the regional scale through methods such as airborne mass balance, atmospheric transport models, and enhancement ratios with well-constrained pollutants, along with approaches such as inverse modeling (e.g., National Oceanic and Atmospheric Administration (NOAA) verification studies), which measure atmospheric levels of emissions and attempt to allocate contribution among potential sources. The first type of study can lead to direct improvements to or verification of inventory estimates. The second type of study can provide general indications of potential over- and under-estimates in existing data. Several of these recent studies are discussed below.

    An article published last year in the peer-reviewed journal Science reviewed 20 years of technical literature on natural gas emissions in the U.S. and Canada and compared various emissions estimates from top down (e.g., aircraft) and bottom up (e.g., inventory) studies. The authors found that inventories consistently underestimate actual methane emissions.139 Similarly, a study published in May 2014 by researchers from NOAA and the University of Colorado, Boulder, estimated methane emissions from oil and gas production areas using atmospheric hydrocarbons gathered while flying over the Denver-Julesberg Basin. This study estimated that hourly methane emissions from oil and gas sources in that basin are three times higher than would be expected based on estimates derived from data reported under the EPA GHGRP.140

    139 A. R. Brandt et al., Methane Leaks from North American Natural Gas Systems, Science, 733 (Feb. 14, 2014), http://www.sciencemag.org/content/343/6172/733.full.

    140 Gabrielle Pétron et al., A new look at methane and nonmethane hydrocarbon emissions from oil and natural gas operations in the Colorado Denver-Julesburg Basin, Journal of Geophysical Research: Atmospheres, 6836 (June 3, 2014), http://onlinelibrary.wiley.com/doi/10.1002/2013JD021272/pdf.

    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 Science studies discussed above, are particularly relevant to this rulemaking.

    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.141 The study focused on methane emissions at 190 sites (focusing on ongoing production activity and well completion emissions) operated by nine natural gas companies. It also found that emissions from well completions were smaller than previously thought (apparently due to the EPA's requirement for reduced emission completions, which can reduce venting from well completions by 99 percent).142 Phase II of the study, which looked at wells operated by 10 companies, found that for emissions from liquids unloading and pneumatic devices, a small percentage of sources account for the majority of the emissions from these categories.143 Nineteen percent of pneumatic devices produced 95 percent of the emissions that were attributable to the devices, while 20 percent of wells that vented during liquids unloading produced 65 to 83 percent of the emissions from those sources.144 The study further found that average emissions from pneumatic controllers are higher than EPA's previous estimates, which are the basis for the emissions factors used in calculating gas waste.145

    141 David T. Allen et al., Measurements of Methane Emissions at Natural Gas Production Sites in the United States, 17768 (Oct. 2013), The Proceedings of the National Academy of Sciences of the United States of America, 17768 (Oct. 2013), http://www.pnas.org/content/110/44/17768.full.pdf.

    142 Ibid, 17769-70.

    143 David T. Allen et al., Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers, 636 (Dec. 9, 2014), Environmental Science and Technology, available at http://pubs.acs.org/doi/abs/10.1021/es5040156.

    144 Ibid.

    145 Ibid. at 638.

    A February 2015 study from Colorado State University, entitled Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results, 146 found wide variations in the amount of methane leaking at gathering and processing facilities. Another study, Analyzing Methane Emissions from Upstream Oil and Gas Production Operations, 147 conducted by researchers at the Houston Advanced Research Center and the EPA, analyzed fence line data on methane emissions at well production sites. It found that unpredictable events, such as malfunctions and leaks, likely have a strong influence on emissions rates.148 In addition, a recent study questions the accuracy of the sampler used in the University of Texas and other studies. The new study, published in the journal Energy Science & Engineering, asserts that the University of Texas researchers used a sampler that can fail under certain conditions, leading to “severe” underreporting of natural gas emissions.149 Other sources of information also reinforce concerns about the volumes of lost gas. In October 2014, an analysis of satellite measurements from 2002-2012 by scientists from the National Aeronautics and Space Administration (NASA) and the University of Michigan identified a 2,500-square-mile (about half the size of the State of Connecticut) concentration of methane located over the Four Corners area in Arizona, Colorado, New Mexico, and Utah.150 The study's lead author indicated that the emissions likely come from natural gas production and processing equipment (although not from hydraulic fracturing, as much of the data predates its upsurge) in the San Juan Basin in New Mexico, which produces natural gas from conventional gas production, oil production, and coalbed methane.151

    146 Austin L. Mitchell et al., Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results, 3219 (Feb. 2015), Environmental Science and Technology, available at http://pubs.acs.org/doi/abs/10.1021/es5052809.

    147 Birmur Guven et. al., Analyzing Methane Emissions from Upstream Oil and Gas Production Operations, (Nov. 2014).

    148 Ibid.

    149 Howard, Touché, University of Texas study underestimates national methane emissions at natural gas production sites due to instrument sensor failure, Energy Science & Engineering (Aug. 4, 2015).

    150 NASA news release, Oct. 9, 2014 available at http://www.nasa.gov/press/2014/october/satellite-data-shows-us-methane-hot-spot-bigger-than-expected/#.VLbQ0PnF9sE.

    151 Ibid.

    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.152 Data indicate that emissions from gas production activities vary from basin to basin. This variation may be due to characteristics of the natural gas, the amount of natural gas processing that is necessary, and the condition of the natural gas gathering, compression and transportation system. Also, some of the older studies may tend to overestimate current losses in some respects, as recent EPA and State regulations, as well as voluntary actions by industry, have substantially reduced the volumes of gas lost from some sources, such as gas well completions.

    152 Jeff Peischl, T. B. Ryerson, K. C. Aikin, J. A. de Gouw, J. B. Gilman, J. S. Holloway, B. M. Lerner, R. Nadkarni, J. A. Neuman, J. B. Nowak, M. Trainer, C. Warneke, D. D. Parrish, Quantifying atmospheric methane emissions from the Haynesville, Fayetteville, and northeastern Marcellus shale gas production regions, Journal of Geophysical Research: Atmospheres, 120 (5), pp. 2119-2139.

    Most recently, a new study by Zavala et al., published in the Proceedings of the National Academy of Sciences, developed new techniques to reconcile bottom up and top down estimates of methane emissions from oil and gas production in the Barnett Shale region in Texas.153 This study found that in this region, methane emissions from oil and gas production and processing are almost twice as high as would be estimated based on the EPA GHG Inventory, and are 3.5 times higher than would be estimated based on EPA GHGRP data.154 It further found that the emissions from these sources in this region are dominated by a relatively small number of high emitters, with, at any given time, 2 percent of the facilities contributing half of the emissions, and 10 percent contributing 90 percent of the emissions.155

    153 Zavala-Araiza et al., Reconciling divergent estimates of oil and gas methane emissions, Proceedings of the National Academy of Sciences, vol. 112, no. 51, 15597-15602 (Dec. 22, 2015).

    154 Ibid. at 15599.

    155 Ibid. at 15600.

    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.

    I. Examples of and Gaps in Existing Waste-Reduction and Related Efforts 1. State Activities

    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.

    (a) Alaska

    The State of Alaska adopted regulations in the 1970s to address high rates of flaring.156 Since then, the State has prohibited venting or flaring of gas except in narrowly defined circumstances: Testing a well before regular production; fuel that maintains a continuous flare; de minimis venting of gas incidental to normal oil field operations; and flaring or venting gas for no more than 1 hour during an emergency or operational upset.157 The practical effect of this prohibition has been widespread reinjection of associated gas into the field for conservation and oil recovery purposes.158 Alaska estimates that roughly 0.4 percent of gas production is flared, which is far lower than in most other States.159

    156 Alaska Administrative Code Title 20—Chapter 25 235, Gas Disposition, available at http://doa.alaska.gov/ogc/Regulations/RegIndex.html.

    157 Ibid.

    158 Telephone call with BLM staff and State of Alaska, Oil and Gas Conservation Commission (April 30, 2015).

    159 Ibid.

    (b) Colorado

    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.160 The Colorado Department of Public Health and Environment, Air Quality Control Commission has instituted regulations similar in many ways to the EPA's existing NSPS for new and modified hydraulically fractured gas wells and gas processing facilities.161 The Colorado regulation includes some aspects of EPA's NSPS, and expands on the EPA standards in other areas. For example, the Colorado rule requires reduced emissions completions for most oil and gas well completions and recompletions, whereas EPA's NSPS currently applies only to hydraulically fractured or refractured gas well completions in developed gas fields. Colorado has also adopted some requirements that are independent of the EPA NSPS. For instance, under the reduced emissions completion process, operators must minimize venting “to the maximum extent practicable.” 162

    160 Colorado Air Quality Control Commission Regulations, Regulation 7, Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions (Emissions of Volatile Organic Compounds and Nitrogen Oxides).

    161 For further information about EPA's NSPS standards for this source category, see Section IV.I.3 of this preamble below.

    162 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Sections XII, XVIII.

    In addition to requiring green completions, Colorado's rules: Establish requirements for pneumatic controllers;163 require a comprehensive LDAR program;164 set standards for liquids unloading;165 establish emission standards for storage vessels;166 and require storage tank emissions management (STEM) plans, which would identify strategies to minimize emissions from storage vessels during normal operations.167 BLM has several memoranda of understanding with the Colorado Oil and Gas Conservation Commission regarding permitting, inspection, and enforcement relating to oil and gas activities on BLM lands.168

    163 Ibid. at Section XVIII.

    164 Ibid. at Section XVII.F.

    165 Ibid. at Section XVII.H.

    166 Ibid. at Sections XII.D-F; XVII.C.

    167 Ibid. at Section XVII.C.2.

    168 The MOUs are available at http://cogcc.state.co.us/gov.html#/federal.

    (c) Montana

    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.169 After completion of a gas well, no gas may be permitted to escape, except gas required for periodic testing or cleaning of the well bore.170 If, after well completion, the operator intends to flare gas production in excess of 100 Mcf per day, the operator must obtain a variance from the oil and gas board.171 The operator must submit a production test and a statement justifying the need for a variance, including information such as potential human exposure; relative isolation of location; measures to restrict public access to the location; low gas volume; and low BTU content.172 The board may elect to restrict production until the gas is marketed or otherwise beneficially used.173

    169 Administrative Rules of Montana, Section 36.22.1221(1).

    170 Ibid. at 36.22.1219.

    171 Ibid. at 36.22.1220(1-2).

    172 Ibid. at 36.22.1221(2).

    173 Ibid. at 36.22.1221(3).

    (d) North Dakota

    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 2015.174 The policy and order require well operators to meet flaring reduction targets according to a prescribed time line.175 The gas capture requirements for each operator include a target of capturing at least 74 percent of production by October 2014.176 The target then rises over time to a target of capturing at least 91 percent of production by October 2020.177 The operator may show compliance with the target at each well, or on a field, county, or statewide basis.178

    174 North Dakota Industrial Commission Order No. 24665 (July 1, 2014), available at https://www.dmr.nd.gov/oilgas/or24665.pdf; North Dakota Industrial Commission Order No. 24665 Policy/Guidance Version 102215, available at https://www.dmr.nd.gov/oilgas/GuidancePolicyNorthDakotaIndustrialCommissionorder24665.pdf.

    175 Ibid.

    176 Ibid.

    177 Ibid.

    178 Ibid.

    North Dakota's policy includes additional requirements intended to help operators reach the targets.179 One component of the policy requires that all applications for permits to drill be accompanied by gas capture plans.180 The State's goal is to ensure that options for capturing any natural gas discovered are fully evaluated before a well is drilled. North Dakota also requires the gas capture plan to be provided to midstream processing companies so they can plan accordingly.181

    179 Ibid.

    180 Ibid.

    181 Ibid.

    The policy provides for oil production to be restricted from wells where the operator does not meet the flaring reduction targets.182 Production is restricted to no more than 200 bbl of oil per day for those wells capturing more than 60 percent of the gas production, but less than the applicable target percentage.183 Production is restricted to no more than 100 bbl of oil per day from those wells capturing less than 60 percent of produced gas.

    182 Ibid.

    183 Ibid.

    (e) Pennsylvania

    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.184

    184 Pennsylvania Department of Environmental Protection, Air Quality, Air Quality Permit Exemptions, http://www.elibrary.dep.state.pa.us/dsweb/Get/Document-96215/275-2101-003.pdf (August 10, 2013) at 8-11.

    (f) Utah

    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.185

    185 State of Utah, Department of Environmental Quality, Division of Air Quality, Approval Order: General Approval Order for a Crude Oil and Natural Gas Well Site and/or Tank Battery, DAQE-AN1492500001-14 (June, 5, 2014).

    (g) Wyoming

    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.186 Among other things, the rule requires emissions from vessels with uncontrolled VOC emissions from flashing of 4 tpy or more to be controlled by 98 percent,187 emissions from pneumatic pumps to be controlled by 98 percent,188 high-bleed pneumatic controllers to be replaced with low-bleed controllers,189 and operators to establish LDAR programs with at least quarterly inspections.190

    186 Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    187 Ibid. at Section 6(c)(i)(A).

    188 Ibid. at Section 6(e).

    189 Ibid. at Section 6(f).

    190 Ibid. at Section 6(g).

    2. Voluntary Industry Efforts

    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.191 Individual companies voluntarily use some of the approaches proposed here to reduce their natural gas losses through venting, flaring, and leaks and boost profitability.

    191See, e.g., EPA, Lessons Learned from Natural Gas STAR Partners, Reduced Emissions Completions for Hydraulically Fractured Natural Gas Wells, available at http://www3.epa.gov/gasstar/documents/reduced_emissions_completions.pdf.

    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 pioneered some of what are now the most widely-used, innovative technologies and practices to reduce methane emissions. These include green completions for hydraulically fractured wells, artificial lift systems for well maintenance, pneumatic controllers and pumps with no or low gas releases, and infrared cameras for leak detection. Natural Gas STAR partners from the oil and gas production sector reported that they achieved about 50 Bcf of methane emissions reductions in 2013.192

    192 EPA Natural Gas STAR, Accomplishments, http://www3.epa.gov/gasstar/accomplishments/index.html.

    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.193

    193 EPA Natural Gas Star Methane Challenge, Program Proposal, http://www3.epa.gov/gasstar/methanechallenge/index.html.

    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.” 194 These companies aim “to develop yearly, sliding-scale emission intensity goals for the entire value chain and each sector within the value chain,” and use a flexible approach to achieve reductions.195

    194 International Business Times, “Six Major Oil and Gas Firms Agree to Cut Potent Methane Emissions Ahead of UN Climate Change Summit, (Sept. 23, 2014), http://www.ibtimes.com/six-major-oil-gas-firms-agree-cut-potent-methane-emissions-ahead-un-climate-change-summit-1693517; http://www.gastechnology.org/CH4/Documents/Fiji-George-CH4-presentation-Sep2014.pdf.

    195 Our Nation's Energy (ONE) Future Coalition, http://www.gastechnology.org/CH4/Documents/fiji-George-CH4-presentation-Sep2014.pdf.

    3. EPA Air Quality Requirements

    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.196 These standards require new hydraulically fractured gas wells to use a process termed a “reduced emission completion” or “green completion” to capture natural gas that would otherwise be released in the well-completion process.197 EPA estimated that this requirement reduces VOC emissions from the hydraulic fracturing process by 95 percent.198 EPA allows for flaring instead of green completions for new exploratory or delineation wells, on the assumption that these types of wells are generally not near pipeline infrastructure to transport captured gas. EPA also does not require green completions for wells where there is not sufficient pressure to route the gas to a gathering line, instead allowing operators to flare the gas that would otherwise be released.

    196 U.S. EPA, Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews; Final Rule, 77 FR 49490 (Aug. 16, 2012).

    197 40 CFR 60.5375.

    198 U.S. EPA, Overview of Final Amendments to Air Regulations for the Oil and Natural Gas Sector, Fact Sheet, available at http://www3.epa.gov/airquality/oilandgas/pdfs/20120417fs.pdf.

    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.199 The standards also apply to new and modified high-bleed pneumatic controllers powered by natural gas, which are defined as pneumatic controllers that emit more than 6 scf/hour.200 The standards limit the bleed rate for pneumatic controllers at well sites and gathering and boosting stations to 6 scf/hour, and they require zero VOC emissions from pneumatic controllers located at processing plants.201 In practice, this standard requires operators to replace high-bleed pneumatic controllers with low-bleed or no-bleed devices. New, modified, and reconstructed storage vessels at these locations (including well sites) are also covered by the 2012 requirements.202 They require new storage vessels with VOC emissions of at least 6 tpy to reduce those emissions by at least 95 percent.203 In addition, the 2012 standards strengthened existing leak detection standards for natural gas processing plants.204

    199 40 CFR 60.5380; 40 CFR 60.5385.

    200 40 CFR 60.5390.

    201 Ibid.

    202 40 CFR 60.5395.

    203 Ibid.

    204 40 CFR 60.5400.

    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.205 The EPA proposes to establish both methane and VOC standards for several emission sources not covered by the 2012 NSPS, including hydraulically fractured oil well completions, pneumatic pumps, and fugitive emissions from well sites and compressor stations. In addition, the EPA proposed methane standards for certain emission sources that are currently regulated for VOCs but not for methane, and proposed to extend VOC standards and create methane standards for equipment used widely in the industry.206

    205 80 FR 56593, Sept. 18, 2015.

    206 Ibid.

    In addition, the EPA proposed to issue Control Technique Guidelines (CTGs), which States could adopt in nonattainment areas to reduce methane emissions from existing sources in the oil and gas production sector.207

    207 Ibid.

    4. Need for BLM Requirements

    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 areas, and very little oil and gas is produced from BLM-administered leases in such areas. Third, because the EPA's legal authorities differ from those of the BLM, the proposed EPA regulations do not cover all BLM-regulated activities, such as well maintenance and liquids unloading.

    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.

    V. Discussion of the Proposed Rule

    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.

    A. Measures To Reduce Waste

    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.

    1. Venting or Flaring of Associated Gas From Producing Oil Wells.

    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.

    (a) Quantities of Gas Vented or Flared

    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).208 Of that total volume of flared gas, 71 Bcf was flared oil-well gas while about 5 Bcf was flared gas-well gas. Most of the flared oil-well gas volume appears to be associated gas flaring, with the balance coming from other sources such as well testing and emergency flaring. Flared gas represents 2.6 percent of the total gas production from BLM-administered leases in 2013, enough to supply over 1 million households.209

    208 RIA at 3.

    209 Based on an estimate of 74 Mcf of gas used per household per year. See footnote 2.

    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.210 The data also show that these volumes have increased dramatically since 2009, while oil production increased in North Dakota and either remained relatively constant or declined in New Mexico and South Dakota. For example, between 2009 and 2013, flared oil-well gas in New Mexico increased by 2.3 percent, even as oil production decreased by 3 percent, and in South Dakota flaring increased by 1.3 percent even as oil production fell by 45 percent.211 Meanwhile, the increase in oil-well gas flaring in North Dakota appears to have tracked closely with the increase in oil production (each increased by roughly 350 percent over that period).212

    210 RIA at 203.

    211 Ibid.

    212 Ibid.

    (b) Technologies To Address Flaring

    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.213 In some cases, line capacity can be increased by adding more compressors to boost pressure. Similarly, industry has long used some of this gas on-site to pneumatically control equipment or fuel various types of equipment, including such items as drilling rigs, artificial lift equipment or heater/treater equipment.

    213 Pipeline and Gas Journal, Billions Needed to Meet Long-Term Natural Gas Infrastructure Supply, Demands (April 2009) http://pipelineandgasjournal.com/billions-needed-meet-long-term-natural-gas-infrastructure-supply-demands?page=4.

    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.214

    214See Carbon Limits (providing detailed evaluation of new and emerging gas utilization technologies).

    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 (e.g., propane, butane, etc.) at a gas processing plant, well-site equipment capable of stripping NGLs into a mixed liquid is available. This technology is particularly applicable in situations where high Btu associated natural gas is being flared due to lack of gas capture infrastructure. The NGLs can be stripped from the gas stream in the field and stored in tanks at the well site. Trucks would transport the stored NGLs to a gas processing plant for sale. The remaining lower Btu gas would continue to be flared, but typically with a higher combustion efficiency than mixed gas. Conservation of the NGLs from a gas stream would reduce waste, add energy to the domestic supply, and increase royalty payments to the Federal Government and tribal governments.

    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.

    (c) Factors Driving Flaring

    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, inadequate maintenance or oversight can result in avoidable waste of gas.

    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.215

    215 Phone conversation with BLM, Planning and Environmental Coordinator, Miles City, MT, September 2014.

    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.216

    216 Letter from North Dakota Oil and Gas Division to Operators, Re: Gas Capture Plans Required on All APD's (May 8, 2014).

    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.217 The GAO also identified a lack of operator awareness of the available cost savings, limited capital availability for small companies, and institutional inertia as reasons that companies fail to capture the economic benefits of investing in waste reduction measures.218 In addition, operators typically consider only the costs and revenues of gas capture with respect to their individual operation. But in many instances, when costs and revenues are evaluated across a larger area, such as a group of wells that would share access to a gas transmission line and processing plant, gas capture that may appear less economically attractive to an individual operator may be more economical if all of the wells in that area were capturing and selling their gas. This concept is recognized in the existing requirements under NTL-4A, which directs the Supervisor to consider “the economics of a field wide plan” in evaluating the feasibility of requiring capture.219

    217 GAO-11-34 (Oct. 2010) at 24.

    218 Ibid.

    219 44 FR 76600 (Dec. 27, 1979).

    (d) Proposals To Reduce Waste From Venting and Flaring

    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.

    (i) Phasing Out Routine Venting

    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 loss of gas is uncontrollable or venting is necessary for the safety of workers and others on the site; (3) When the gas is leaking from a storage vessel under circumstances that do not trigger the flaring requirements of proposed § 3179.203; or (4) When the gas is vented through operation of a natural gas-activated pneumatic controller or pneumatic pump that complies with the equipment requirements of proposed § 3179.201. As a practical matter, the BLM believes that the great majority of associated gas routinely lost from oil production wells is flared, rather than vented, and the proposed prohibition on venting would further reduce losses through venting. Thus, the discussion that follows generally references flaring, which is the main focus of these provisions.

    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.

    (ii) Limits on Rates of Flaring

    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.

    (a) Proposed Per-Well Flaring Limit

    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.220

    220 RIA at 33-35.

    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.221 Operators have full discretion in how they choose to meet a rate-based flaring limit, with the result that compliance strategies may vary. For example, operators with wells that are only slightly over the flaring limit may choose to comply by slowing the rate of production until either: (1) The well is connected to pipeline infrastructure; or (2) Well decline brings the rate of gas production under the flaring limit. In the first instance, the over-the-limit quantity of gas would ultimately be conserved—in fact, even more gas might be conserved because the operator is likely to capture all of the gas that would otherwise have been flared. In contrast, in the second instance, the over-the-limit quantity of gas would still be flared, just later in time. Thus, there is substantial uncertainty in analyzing the impact of a flaring limit.

    221 Data supplied by ONNR.

    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 understate reductions in flaring). With these competing assumptions in place, the projected reductions in flaring that might be achieved under different numeric limits are:

    • 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.222 As applied, the numeric limit proposed by the BLM would be somewhat less stringent than the State limits, because operators would be able to average flaring across all of the wells on a lease, rather than being required to meet the limit at each individual well. This approach incorporates some of the flexibility allowed by North Dakota, where operators can show compliance with the State's flaring limits on a field, county, or state-wide basis. In addition to reducing waste of gas through flaring, we believe this proposed approach would give operators more clarity about when they may flare, and reduce administrative burdens for the BLM, compared to the current approach to obtaining approval for flaring under NTL-4A. Operators would no longer have to submit applications to obtain approval for flaring from each individual well, and the BLM would no longer need to review and decide on each of those requests. Currently, some field offices receive hundreds of flaring applications each year, and processing these applications on a case-by-case basis uses BLM resources that could be used to process applications for permit to drill, process right-of-way applications, and conduct inspections, among other activities.

    222 Wyoming Operational Rules, Drilling Rules Section Ch. 3, Section 39(b), available at http://soswy.state.wy.us/Rules/RULES/9584.pdf (60 Mcf/day); Utah R649-3-20, Gas Flaring or Venting Section 1.1, available at (http://www.rules.utah.gov/publicat/code/r649/r649-003.htm#T20 (1,800 Mcf/mo.).

    (b) Phase-In of the Proposed 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.

    (c) Alternative Flaring Limits or Renewable, 2-Year Exemption

    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.

    (i) Alternative Flaring Limits

    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.” 223 Given the substantial variation in how the BLM has interpreted and applied this standard, the BLM is proposing to establish a refined formulation of this test, to allow for a more uniform interpretation going forward. In particular, in some instances in the past, even small net costs have been viewed as meeting the test under NTL-4A, as any net cost might theoretically cause an operator to abandon a well earlier than it otherwise would have. In light of the BLM's statutory obligation to reduce waste of natural gas from venting, flaring, and leaks, however, the BLM believes that an operator must demonstrate more than a negligible economic impact in order to qualify for an exemption from the flaring limit. Thus, we propose to allow an exemption only on a showing that the net costs of compliance with the flaring limit would be sufficient to cause the operator to cease production and abandon “significant” recoverable oil reserves. The BLM requests comment on this approach.

    223 NTL-4A, IV.B.

    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 15 years, whichever is less. This is similar to the information that NTL-4A currently requires operators to provide in a request for approval of flaring, although the proposed regulations are more specific. NTL-4A currently requires an applicant for royalty-free flaring to submit “all appropriate engineering, geologic, and economic data in support of the applicant's determination that conservation of the gas is not viable from an economic standpoint and if approval is not granted to continue the venting or flaring of the gas, that it will result in the premature abandonment of oil production and/or the curtailment of lease development.” 224 Pursuant to this language in NTL-4A and guidance from individual BLM State offices, operators generally give the BLM information on projected oil and gas production, revenue projections, costs, and returns on investment under scenarios in which the gas is and is not captured, although the specific information submitted varies between applicants and across BLM field offices and States.

    224 44 FR at 76600 (Dec. 27, 1979).

    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.

    (ii) Renewable, 2-Year Exemption

    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 Improving Utilization of Associated Gas in US Tight Oil Fields, 225 suggests that on-site capture is most cost-effective within a 20-25 mile radius of gas processing facilities.226 Existing leases located more than 50 miles from such facilities are thus unlikely to be able to avail themselves of this technology. (While leases located more than 25 but less than 50 miles from gas processing facilities might similarly find on-site capture less cost-effective, that might not always be the case. Those leases could make a case-by-case showing under the proposed provision for alternative flaring limits.)

    225 Hereinafter “Carbon Limits.” The study is available at http://www.catf.us/resources/publications/files/Flaring_Report.pdf.

    226 Ibid. at 34.

    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.

    (d) Request for Comments

    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.

    (iii) Waste Minimization Plans for Applications for Permit To Drill

    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 unavailable; and the volume and percentage of produced gas that the operator is currently flaring from wells in the same field. In addition, the operator must certify that it has provided one or more midstream processing companies with information about its production plans, including the anticipated completion dates and gas production rates of the proposed well or wells. We request comment on whether the waste minimization plan provisions should also require an operator to identify the projected gas production volumes that would be moved by pipeline or by truck.

    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.227 North Dakota regulators have identified the requirement for gas capture plans as a highly effective element of their requirements to reduce flaring.228

    227 Letter from North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division to all Hearing Applicants, re Gas Capture Plan Required Hearing Exhibit (Sept. 16, 2014).

    228 Telephone Communication from North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division to BLM Staff, (May 13, 2015).

    (iv) Estimating or Measuring Quantities of Flared or Vented Gas

    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 (i.e., flared and/or vented) from that flare stack or manifold.

    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.

    (v) Costs and Benefits of These Proposals

    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.229

    229 RIA at 69.

    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 connected to pipeline infrastructure, the rate of flaring (specifically, whether the rate was at least 50 percent above the flaring limit, or whether the rate was within 40 Mcf/day of the flaring limit), and the distance from the nearest gas processing plant (specifically whether the well was more than 50 miles, less than 20 miles, or between 20 and 50 miles from the nearest gas processing plant) for each lease where these data were available. We then constructed eight possible operator response scenarios based on combinations of these characteristics. We evaluated how operators in each scenario might respond to the flaring limit (e.g., by deferring production, conducting on-site capture, or obtaining an exemption), assigned costs for each type of response, calculated the number of leases that would fall into each response category, and derived an estimate of overall costs. The RIA provides additional detail on our analysis.

    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.230

    230 RIA at 60.

    (e) When Flared Gas Is Subject to Royalties

    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.

    (i) Unavoidable Losses of Gas

    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 indicates that adequate testing to determine a well's production capacity can almost always be conducted within the 20 MMcf volume threshold. The current 50 MMcf threshold is seldom, if ever, exceeded in actual well testing operations. The BLM specifically seeks comments on the amount of gas that should be allowed to be flared royalty-free during initial production testing.

    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.

    (ii) Avoidable Losses of Gas

    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.

    (f) Alternative and Additional Approaches

    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.

    2. Leaks (a) Estimates of Quantities of Gas Leaked

    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 of leaks or other fugitive emissions from various components, including valves, fittings, pumps, storage vessels and compressors on well site operations on BLM-administered leases.231 This quantity of gas would supply nearly 60,000 homes each year.232

    231 RIA at 19.

    232 Based on an estimate of 74 Mcf of gas used per household per year. See footnote 2.

    (b) Technologies and Practices To Reduce Leaks

    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.233 Further, over 90 percent of gas leak emissions are from leaks that could be repaired with less than a 1-year payback period.234 Given that leak repair is generally economical, the key question is how the cost of leak detection compares with the value of the gas that could potentially be saved by repairing leaks.

    233 Carbon Limits, 16.

    234 Carbon Limits, 16.

    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.235 Also, Wyoming has regulations that require operators in the Upper Green River Basin nonattainment area to develop LDAR programs if their facilities emit more than an estimated 4 tons of VOCs each year.236

    235 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.F.

    236 Wyoming Operational Rules, Drilling Rules Section Ch. 8, Section 6(g), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    (i) Auditory, Visual, and Olfactory (AVO) Method

    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.237 AVO inspections are not, however, very effective at catching smaller or less obvious leaks, which can be a source of significant wasted gas.

    237 API, 2014.

    (ii) Portable Analyzers

    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-$12,000.238

    238 API, 2014.

    One standard approach for using portable analyzers is “Method 21,” the EPA's method for detecting VOC emissions from leaking equipment.239 Method 21 provides the specifications and performance criteria that must be used under EPA's regulations to detect leaks using portable analyzers.

    239 40 CFR part 60, App. A-7.

    (iii) Optical Gas Imaging (Infrared Camera)

    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.240 In its recent proposed rule, EPA also notes the advantages of OGI compared to a portable analyzer.241 Several studies discussed in EPA's white paper on leak detection estimated that OGI can monitor 1,875-2,100 components per hour.242 In comparison, the average screening rate using a portable analyzer is roughly 700 components per day.243 Although EPA noted that these studies may underestimate the amount of time necessary to thoroughly monitor for fugitive emissions using OGI instruments, EPA stated that it still believes that the use of OGI can reduce the amount of time (and therefore the cost) necessary to conduct fugitive emissions monitoring, because multiple fugitive emissions components can be surveyed simultaneously.244

    240 GAO-11-34 (Oct. 2010) at 34.

    241 80 FR 56593, 56634.

    242 Ibid.

    243 Ibid.

    244 Ibid.

    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 $10,000.245 Calculated on an individual facility basis, another study found that the average cost of hiring an external service provider to conduct a leak survey and provide a report is: $400 per individual well site (with a single well); $600 per single well battery, which includes additional equipment on site; $1,200 per multi-well battery; and $2,300 per compressor station.246 The BLM has also received information from external service providers indicating that costs can be substantially lower than these, and we request comment on this point.

    245 API, 2014.

    246 Carbon Limits, 14, 32.

    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.247 ) For compressor stations, roughly 10 percent had no leaks, while almost 25 percent leaked at 500 Mcf per year or more.

    247 See footnote 2.

    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.248 Broken down by facility type, it found that surveys at well sites are cost-neutral measured on a ton of avoided CO2-e basis, and that surveys at compression stations produce net savings. Specifically, on average, the net present value (NPV) of applying LDAR to an individual well site or well battery was a loss of $35, assuming recovered gas at $4 per Mcf. The average cost saving across all compressor stations surveyed was $3,376. Moreover, the authors note that most of the facilities in the study were Canadian facilities that are already inspected for leaks every 1 to 2 years, and thus the current leak rates—and, consequently, proceeds from repairs—at U.S. facilities without leak inspection programs would be expected to be higher.249

    248 Carbon Limits. The study increased the cost estimates by 50 percent to account for the internal costs to a firm of arranging for this work, and it assumed a 7 percent discount rate and $4 per Mcf value of gas.

    249 Ibid.

    (iv) Continuous Emissions Monitoring Systems and Other New Technologies

    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.250 Due to the dispersed nature of potential leaks within the area of concern (compared to the concentrated gases in a flue gas stream), challenges remain in developing a CEMS (standalone or mobile) that has the requisite sensitivity to detect leaks under a variety of atmospheric and field conditions. One possibility is to use a CEMS as an area monitor for fugitive emissions, which would then alert the operator for the need to use a more focused leak detection device to pinpoint the leak needing repair. Research is continuing to determine if CEMS could supplement or be a viable alternative to current leak detection instruments.

    250 Briefing from Dr. Bryan Wilson, Program Director, Advanced Research Projects Agency—Energy on O&G emission projects the agency is funding, August 3, 2015.

    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.251 In December 2014, this $30-million, 3-year program announced support for 11 new projects that are developing low-cost, highly sensitive systems that detect and measure methane associated with the production and transportation of oil and natural gas.252

    251 ARPA-E, http://arpa-e.energy.gov/?q=arpa-e-programs/monitor.

    252 Briefing from Dr. Bryan Wilson, Program Director, Advanced Research Projects Agency—Energy on O&G emission projects the agency is funding, August 3, 2015.

    (iv) LDAR Programs

    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 (i.e., alloys, gaskets, filters, etc. that are wear and/or leak resistant), active corrosion monitoring, the application of corrosion and scale inhibitors, use of maintenance records to identify components at risk of failure, and pre-emptive replacement of at-risk equipment.253

    253 API, June 13, 2014. Re: EPA VOC/Methane White Paper on Oil and Natural Gas Sector Leaks. Pages 7-9.

    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.254 The visits are tracked using GPS, which is installed in each truck.255 According to the operator, any leaks are fixed within days, new facilities are leak-tested prior to production, and most wells have Remote Terminal Units installed, which monitor gas flow rate and volume, static pressure, differential pressure, temperature, controller settings, plunger arrivals/rod pump status/compressor status and both oil and water tank levels.256 The data flow via solar-powered telemetry at 1-minute intervals. Alarms are triggered if there are sudden pressure changes or tank level drops, and a lease operator can be dispatched to the well site to investigate.257

    254 Phone conversation with Conoco Phillips on San Juan Basin operation, February 2015.

    255 Phone conversation with Conoco Phillips on San Juan Basin operation, February 2015.

    256 Phone conversations with Conoco Phillips and WPX energy on San Juan Basin operations, February 2015.

    257 Ibid.

    (c) Proposals To Reduce Waste From Leaks—Leak Detection and Repair Programs

    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 proposing under §§ 3179.301 through 3179.305 to require that each operator on a Federal or Indian lease institute an LDAR program that meets specified standards for detection methodology, frequency, and leak repairs, and use this program to inspect each of the operator's well sites and compressor locations.

    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.258 As both agencies have worked to develop their proposed rules, we have shared technical information and communicated extensively. We share the goal of aligning the final requirements for LDAR in the two rules to the maximum extent practicable. At minimum, we would seek to ensure that operators could develop a single LDAR program that meets the requirements of both agencies. We will continue to focus on this issue over the course of the rulemaking process, and we request public comment on how best to achieve this goal.

    258 80 FR 56593, 56611-56614.

    (i) LDAR Options in the Proposed Rule

    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.259 In the EPA 40 CFR part 60 subpart OOOOa rulemaking, OGI is the proposed technology for detecting fugitive emissions.

    259 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.F.3; Wyoming Operational Rules, Drilling Rules Section Ch. 8, Section 6(g).

    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; 260 or (3) A comprehensive LDAR program, approved by the BLM, that includes the use of instrument-based monitoring devices. The standard for approval of options (2) and (3) would be a BLM determination that the alternative device or program meets or exceeds the effectiveness for leak detection of an optical gas imaging device used with the frequency specified in proposed § 3179.303(a).

    260 The BLM could provide notice to all operators that it had found that a specified new technology would satisfy these requirements.

    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 would be considered a leak if the detected concentration were 500 ppm or more above the measured background levels. This would be consistent with the EPA's proposed approach, which provides that a leak would be considered repaired if a portable analyzer, used according to Method 21, indicates concentrations less than 500 ppm above background levels.

    (ii) Frequency of LDAR Inspections

    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.261 Inspection frequency can vary from monthly to annually depending on the magnitude of the emissions.262 Wyoming simply requires quarterly inspections.263

    261 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9 at Section XVIII.F.3.

    262 Ibid.

    263 Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), Section 6(g), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    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).264 If some operators, in fact, experience proportionally fewer leaks than others, this would support allowing the frequency of periodic screening to vary depending on the operator's past history of leak detections. Based on experience in the field, the BLM believes that there are systematic differences among operators' leak rates, but we understand that some recent studies indicate that leak rates are random.265

    264 See Zavala-Araiza, et al., Reconciling divergent estimates of oil and gas methane emissions, Proceedings of the National Academy of Sciences, vol. 112, no. 51, at 15600 (Dec. 22, 2015

    265 Ibid.

    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.266 This study found that annual or semi-annual (twice-yearly) surveys generally resulted in net benefits to the operator—the benefits of leaks avoided exceeded the costs of the surveys—whereas quarterly or more regular surveys imposed net costs on the operator—the costs of the frequent surveys outweighed the benefits of leaks avoided. This study supports starting with a frequency of annual or semi-annual surveys. We request data and comment on the data, methodology, and analysis used in this study.

    266 Carbon Limits.

    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 267 (which would include, for example, separators, heater/treaters, and liquids unloading equipment). If an operator finds no more than two leaks at a site for two consecutive inspections, it may change to annual inspections at that site. If the operator is inspecting semi-annually and finds three or more leaks at a site for two consecutive inspections, it must inspect quarterly. The quarterly rate would continue unless and until an operator finds no more than two leaks in two sequential inspections, at which point it could revert back to twice-yearly inspections. On the other hand, if the operator is inspecting semi-annually and finds no more than two leaks for two consecutive inspections, the operator may reduce the frequency of inspections to once per year, unless and until it finds more than two leaks for two consecutive inspections, which would require it to revert back to semi-annual inspections.

    267 Note that the BLM has proposed to define “facility” in part 3170 as “(1) A site and associated equipment used to process, treat, store, or measure production from or allocated to a Federal or Indian lease, unit, or CA that is located upstream of or at (and including) the approved point of royalty measurement; and (2) A site and associated equipment used to store, measure, or dispose of produced water that is located on a lease, unit, or CA.” 80 FR 40767 (July 13, 2015).

    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.

    (iii) Possible Alternatives to the Proposed LDAR Provisions

    In addition to the BLM's proposed approach, we are taking comments on other possible approaches to reducing waste through LDAR requirements. These include variations on the proposed approach, an alternative approach suggested by a stakeholder, and an alternative method of establishing the inspection frequency.

    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.268

    268 U.S. Energy Information Administration. United States Total 2009 Distribution of Wells by Production Rate Bracket, available at http://www.eia.gov/pub/oil_gas/petrosystem/us_table.html.

    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.269 Based on these studies, DOI does not believe it is appropriate to exclude low-yield wells from any instrument-based inspection requirement, or to allow those wells to be inspected less frequently.

    269 See Zavala-Araiza et al., Reconciling divergent estimates of oil and gas methane emissions, Proceedings of the National Academy of Sciences, vol. 112, no. 51, at 15600 (Dec. 22, 2015).

    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 (e.g., compressors), and at sites with storage vessels. Thus, requiring more frequent inspections at sites with those characteristics, and less frequent inspections at other sites, might be a way to increase the cost effectiveness of the LDAR program by targeting inspections to the sites most likely to produce the largest losses through leaks.

    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 from gas wells, compared to oil wells.270 Assuming these emissions factors are accurate, this indicates that focusing more inspection resources on gas than oil wells would identify and save a relatively larger volume of gas at roughly the same cost.

    270 80 FR 56593, 56635.

    (iv) Requests for Comments on LDAR Alternatives

    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 (e.g., whether finding a certain number of leaks is the appropriate trigger for changing inspection frequency); and

    • 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.271

    271 RIA at 113.

    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.

    (v) Costs of the LDAR Provisions

    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 2026.272 We request data and comment on whether this analysis fully captures the benefits of identifying and fixing high-volume leaks.

    272 RIA at 109.

    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 2026.273

    273 RIA at 108-109.

    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.

    3. Pneumatic Controllers and Pneumatic Pumps

    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 freezing. Diaphragm pumps are used to move larger volumes of liquids, such as to circulate heat trace medium at well sites during cold winter conditions, or to pump out sumps. Similar to pneumatic controllers, pneumatic pumps can operate on gas pressure and emit that same gas from the pump. For the purposes of this proposed rule, the term pneumatic pump means a pump that is operated by natural gas pressure and emits natural gas.

    (a) Estimates of Gas Released From Pneumatic Controllers and Pneumatic Pumps

    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.274 That volume includes releases from high bleed continuous controllers, low bleed continuous controllers, and intermittent controllers. Using prevalence data from the EPA and an analysis of EPA GHGRP data conducted by ICF, we estimate that there are 18,150 high bleed pneumatic controllers on BLM-administered leases, or about 19 percent of the total number of pneumatic controllers on these leases. In addition, using data from the EPA's GHG Inventory, we estimate that about 2.5 Bcf of natural gas was lost in 2013 from pneumatic pumps on BLM-administered leases. That volume includes releases from chemical injection pumps, diaphragm pumps, and gas-assist glycol dehydrator pumps.

    274 RIA at 18.

    (b) Technologies To Reduce Quantities of Gas Released From Pneumatic Controllers and Pneumatic Pumps

    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).275 The EPA NSPS requires new and replacement natural-gas-operated pneumatic controllers at natural gas well sites and gathering and boosting stations to meet the 6 scf/hour limit, unless a higher bleed rate is necessary for safety or to perform the designed function. The EPA NSPS requirement does not currently apply to intermittent pneumatic controllers nor to pneumatic pumps, but the EPA's proposed 40 CFR part 60 subpart OOOOa rulemaking would extend to new or modified pneumatic pumps.276

    275 40 CFR 60.5390.

    276 80 FR 56593, 56610.

    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.277

    277 ICF economic analysis, at 4-4 (base case assumed $4/Mcf price for recovered gas and a 10 percent discount rate/cost of capital).

    The State of Colorado has prohibited use of “high bleed” pneumatic controllers, with limited exemptions.278 Colorado adopted the existing EPA NSPS standards for new pneumatic controllers, prohibiting operators from installing new “high bleed” controllers, and the State required operators to replace all existing high bleed controllers with low-bleed or no-bleed controllers by May 1, 2015.279 The operator may request an exception on the grounds that use of a high-bleed controller is needed for safety or process purposes. As of April 2015, however, the State had not received a single request to use or keep high bleed controllers under this provision.280

    278 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVIII, available at https://www.colorado.gov/pacific/sites/default/files/5-CCR-1001-9_0.pdf.

    279 Ibid. at Section XVIII.C.2.

    280 Email from Daniel Bon, Air Quality Planner, Planning and Policy, Air Pollution Control Division, Colorado Department of Public Health and Environment, to Alexandra Teitz, BLM (April 27, 2015).

    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, 2017.281

    281 Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), Section 6(f), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    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, e.g., to inhibit freezing, and they do not require as much power as larger pumps used in other applications. The EPA's Natural Gas STAR program cites the costs to replace a pneumatic pump with a solar-charged electric pump as about $2,000. Operating costs are minimal, and the lifespans of the solar panels and electric motors are up to 15 and 5 years, respectively. The EPA estimates potential annual natural gas savings of 183 Mcf per pneumatic pump replaced—a volume that would have a sales value of $732 (at $4/Mcf).282

    282 U.S. EPA, Office of Air Quality Planning and Standards, Oil and Natural Gas Sector Pneumatic Devices Report for Oil and Natural Gas Sector Pneumatic Devices Review Panel (April 2014) at 53.

    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 pumps and either combust it or re-pressure and route it into the natural gas sales stream.

    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, 2017.283

    283 Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), Section 6(e), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    (c) Proposals To Reduce Waste From Pneumatic Controllers and Pneumatic Pumps

    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.284 Given the EPA requirements for new pneumatic controllers and the fact that, on average, this waste-reduction measure would save companies money, the BLM believes that continued reliance on high-bleed pneumatic controllers leads to avoidable waste of public resources, except in limited situations.

    284 Phone conversation with Conoco Phillips on San Juan Basin operation, February 2015.

    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.285

    285 RIA at 78.

    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, 2017.286

    286 Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(e) (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

    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.287

    287 RIA at 82.

    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.288

    288 RIA at 81.

    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.

    4. Storage Vessels

    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.289 The EPA standards also provide that if a storage tank that initially emitted at least 6 tpy of VOCs now emits less than 4 tpy without considering any emission controls in place for a period of 12 consecutive months, emission controls are not required if the operator monitors regularly to ensure that emissions do not exceed 4 tpy.290 Unmodified storage vessels that were in place as of August 23, 2011, are currently allowed to vent vapors uncontrolled, unless subject to State controls.291 EPA requires operators to determine the VOC emission rate within 30 days, and storage vessels must have a cover and closed vent system that meets specifications.292

    289 40 CFR 60.5395.

    290 Ibid.

    291 Ibid.

    292 40 CFR 60.5395, 60.5415-5416.

    Colorado requires the capture or combustion of vapors from storage vessels with a capacity to emit 6 tpy VOC or more.293 The control equipment must reduce hydrocarbons by 95 percent, or by 98 percent if the operator uses a combustion device.294 Storage vessels that require emission control systems are also subject to increased monitoring, and Colorado requires operators to develop STEM plans.295

    293 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.C.

    294 Ibid.

    295 Ibid.

    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.296

    296 Wyoming Operational Rules, Drilling Rules Section Ch. 8, Section 6(d).

    (a) Estimates of Quantities of Gas Lost From Storage Vessels

    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.297 These estimates were calculated using data from the 2015 GHG Inventory and the share of natural gas and crude oil production coming from Federal and Indian lands.

    297 RIA at 18.

    (b) Technologies and Practices To Reduce Gas Losses From Storage Vessels

    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.298

    298 40 CFR part 60 subpart OOOO.

    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 includes both flares and combustors) is $8,900 per year, assuming that a flare device is already in place at the facility.299

    299 76 FR 52738 (Aug. 23, 2011).

    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 rule300 ), the economic viability of a VRU as a storage tank emission control device depends on high production throughput. In other words, net VRU costs rise as production volumes decline.

    300 Ibid.

    (c) Proposals To Minimize Vapor Losses From Storage Vessels

    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.301

    301 40 CFR 60.5395.

    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.302 The threshold is somewhat less stringent than Wyoming's requirements, which apply to facilities with VOC emissions of 4 tpy or more and extend to glycol dehydrators, which the BLM does not propose to regulate.303 The BLM also requests comment on applying a more stringent threshold consistent with Wyoming's requirements.

    302 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.C.

    303 Wyoming Operational Rules, Drilling Rules Section Ch. 8, Section 6(d).

    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).304 We project that these requirements would increase gas production by 0.04 Bcf per year, resulting in cost savings of about $0.1—0.2 million per year (using 7 percent and 3 percent discount rates). They would also reduce methane emissions by 7,000 tpy, producing monetized benefits of $8 million per year in 2017-2019, $9 million per year in 2020-2024, and $11 million in 2025 and 2026. Overall, we estimate that these provisions would result in net benefits of $2 million per year in 2017-2019, $3-4 million per year in 2020-2024, and $5 million in 2025 and 2026, and reduce VOC emissions by 32,500 tpy.305

    304 RIA at 95.

    305 Ibid.

    5. Well Maintenance and Liquids Unloading

    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.

    (a) Estimates of Quantities of Gas Lost Through Well Maintenance and Liquids Unloading

    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.306 These estimates were calculated using data from the GHG Inventory, including the regional prevalence of wells with and without plunger lifts, and emissions factors for each. We chose to calculate emissions using a bottom-up approach for this emissions source because the prevalence of liquids unloading with and without plunger lifts and the emissions factors for each vary across regions. We then applied the prevalence and emissions factors to the number of producing gas wells on Federal and Indian lands as of January 1, 2014.

    306 RIA at 128-129.

    (b) Technologies and Practices To Reduce Gas Losses From Well Maintenance and Liquids Unloading

    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.307 For a $12 million capital investment, BP realized a $6 million total annual savings.308 Automated systems, whether “smart” or more conventional, are particularly useful for wells located in remote areas, typical of BLM lands, as they help maintain the well even when operators are not present.

    307 EPA PowerPoint presentation found at http://www3.epa.gov/gasstar/documents/workshops/fortworth-2006/gremillion.pdf.

    308 Ibid.

    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.309

    309 EPA, Natural Gas STAR Program, 2011, http://www3.epa.gov/gasstar/documents/ll_options.pdf.

    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.310 Other operators use compression to reduce flowing operating pressure, thus reducing flowing bottomhole pressure, which increases inflow from the reservoir. This is a means of achieving higher well-bore velocities. Compression can be used in conjunction with other artificial lift methods.

    310 Ibid.

    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 (e.g., 30 bbl of liquid or less per day). The capital, installation and startup cost of a plunger lift is estimated at $1,900-$7,800,311 but it can reach as high as $20,000.312 Adding a smart automation system is estimated to cost $4,700-$18,000.313

    311 EPA (2014). Oil and Natural Gas Sector Liquids Unloading Process; Report for Oil and Natural Gas Sector Liquids Unloading Process Review Panel. April 2014. Available at http://www3.epa.gov/airquality/oilandgas/pdfs/20140415liquids.pdf, p. 16.

    312 ICF International (2014) Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries, March (2014), p.p. 3-17.

    313 EPA, Natural Gas STAR Program (2011). http://www3.epa.gov/gasstar/documents/ll_options.pdf.

    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 (e.g., rod pumps, beam lift pumps, pumpjacks, and downhole separator pumps). Downhole pumps require an external power source to operate in order to remove the liquid buildup from the well tubing. Capital and installation costs (including location preparation, well clean out, artificial lift equipment, and pumping unit) is estimated at $41,000-$62,000 per well.314

    314 Ibid.

    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.315 To minimize venting associated with liquids unloading, Colorado also requires an operator representative to remain on site during the unloading event.316 The EPA's proposed 40 CFR part 60 subpart OOOOa rulemaking requests comment on “nationally applicable technologies and techniques that reduce methane and VOC emissions” during liquids unloading, but the EPA does not believe it has sufficient data to propose a standard for unloading events.317

    315 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Sections XVII.

    316 Ibid.

    317 80 FR 56593, 56614.

    (c) Proposals To Reduce Waste From Well Maintenance and Liquids Unloading

    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. 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 are seeking comments on the appropriate level and extent of required recordkeeping in the proposed rule, as well as other aspects of this approach to reducing waste from well maintenance and liquids unloading.

    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.318 The proposed requirements would impact the 1,550 wells that are not equipped with plunger lifts, as well as any of the wells equipped with plunger lifts that lack automation (a number the BLM cannot accurately estimate at this time). In addition to the 8,500 wells currently venting during liquids unloading, there is the potential that a number of additional, producing gas wells will develop liquids accumulation issues in the future. Depending on how the operator removes the liquids from the wellbore, those wells could potentially be impacted by the requirements.

    318 RIA at 216.

    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,319 suggesting that under many circumstances their benefits—in terms of increased gas recovery, slowed declines in production, and improved well productivity—exceed their costs.

    319 According to the 2015 GHG Inventory, 13 percent of the gas wells nationwide vent to the atmosphere during liquids unloading, and of those, more than 60 percent lack plunger lifts. RIA at 216. In the Rocky Mountain region, however, where over 90 percent of the gas wells on Federal and Indian lands are located, plunger lifts are far more common than elsewhere in the country. RIA at 217.

    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.320 The BLM does not expect that requiring operators to remain at the well site for such short periods would impose a significant financial burden.

    320 RIA at 217. Source is Shires & Lev-on analysis of API/ANGA survey data.

    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.321

    321 RIA at 85.

    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.322

    322 EPA Natural Gas STAR, Lessons Learned from Natural Gas STAR Partners, available at http://www3.epa.gov/gasstar/documents/ll_plungerlift.pdf.

    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.323

    323 RIA at 87.

    6. Reduction of Waste From Drilling, Completion, and Related Operations

    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.324

    324 RIA at 205.

    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 oil wells.325 If the EPA finalizes that proposal, it appears likely that all new hydraulically fractured or refractured oil and gas wells, other than wildcat and delineation wells, would be required to capture or flare the gas produced from these drilling operations. 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 conventional and hydraulically fractured and refractured wells. The BLM has an independent statutory obligation to minimize waste of oil and gas resources on BLM-administered leases. As proposed, we expect that the BLM waste requirements for well drilling, and completions at both conventional and hydraulically fractured wells would apply to a broader set of wells than the EPA proposal would cover. Finally, if the EPA finalizes a rule regulating hydraulically fractured and refractured oil wells, the BLM anticipates that any operator subject to both sets of requirements (i.e., an operator completing a hydraulically fractured oil well) could satisfy both agencies' requirements by either capturing or flaring the gas that would otherwise be released. 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 complied with any EPA requirements on well completions.

    325 80 FR 56593.

    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 de minimis anticipated incremental production, incremental royalty, and emissions reductions.326

    326 RIA at 74.

    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.327

    327 Ibid.

    7. Additional Opportunities To Reduce Waste From Venting

    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.328 Specifically, that rule requires compressors with wet seals to reduce VOC emissions by 95 percent, which can be met through flaring or gas capture.329 The EPA rule also requires operators of reciprocating compressors to replace the rod packing systems every 26,000 hours of operation or every 36 months, and requires initial performance testing and reporting.330 The BLM has not proposed to adopt similar requirements for operational losses from existing compressors on BLM-administered leases, as we believe that these losses from compressors are not a significant source of waste on those leases. We request comment on whether adopting similar requirements for existing compressors would significantly reduce waste of gas from BLM-administered leases in a reasonable and cost-effective manner.

    328 40 CFR 60.5380-5385.

    329 40 CFR 60.5380.

    330 40 CFR 60.5385.

    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 well drilling, § 3179.101, and completions, § 3179.102, include requirements for the associated flare device to be equipped with an automatic igniter, as we believe that these activities involve more sporadic gas releases, such that an automatic igniter could be helpful in avoiding venting. However, we request comment on whether there are other situations under which automatic igniters should be required, and if so, what deadline should be imposed for the retrofit. For example, the State of Colorado requires that all combustion devices used to control emissions of hydrocarbons be equipped with automatic igniters, and the State gave operators 2 years (until May 1, 2016) to retrofit existing combustion devices.331

    331 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Sections XII.C.1.e, XVII.B.2.d.

    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.332 To the extent that operators do so, the flares must achieve at least a 95 percent removal efficiency for VOCs. Colorado and Wyoming both require combustion devices used to control hydrocarbons from vessels and other sources to achieve at least a 98 percent “design destruction efficiency” or “destruction removal efficiency” for VOCs.333

    332 40 CFR part 60, subpart OOOO.

    333 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.G; Wyoming Operational Rules, Drilling Rules Section Ch. 8, Section 6(c)(1)(A).

    B. Royalty-Free Use of Production

    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.334 When a particular operation involved in placing the oil and gas into marketable condition is performed on the producing lease, unit participating area (PA), or CA, and the operator has met all other requirements, however, it is an appropriate royalty-free use. The production used in that operation is not royalty-bearing because the production is not removed from the lease, unit, or CA.335

    334See, e.g., 30 CFR 1206.55 (Indian oil); 1206.106 (Federal oil); 1206.152(i) and 1206.153(i) (Federal gas); 1206.172(e)(3)(iii)(B) and 1206.174(h) (Indian gas); Devon Energy Corp. v. Kempthorne, 551 F.3d 1030 (D.C. Cir. 2008); Amoco Production Co. v. Watson. 410 F.3d 722 (D.C. Cir. 2005); Amerada Hess Corp. v. Dep't. of the Interior, 170 F.3d 1032 (10th Cir. 1999); Mesa Operating Limited Partnership. v. Dep't. of the Interior, 931 F.2d 318 (5th Cir. 1991); Shoshone and Arapaho Tribes v. Hodel, 903 F.2d 784 (10th Cir. 1990).

    335See Plains Exploration & Production Co., 178 IBLA 327, 335-336, 341-343 (2010).

    C. Royalty Rates on New Competitive Leases

    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 not less than 12.5 percent in amount or value of the production removed or sold from the lease.” 336 Despite the inherent flexibility of this statutory language, the BLM's existing royalty regulation sets a flat rate of 12.5 percent for all new competitive leases.337 The proposed rule would adopt the statutory language, with the result that the “base” royalty rate on competitive oil and gas leases issued after the effective date of this rule would be “not less than” 12.5 percent.

    336 30 U.S.C. 226(b)(1)(A) (emphasis added); see also 30 U.S.C. 352 (applying the Section 226 royalty provisions to leases on acquired land).

    337 43 CFR 3103.3 1(a)(1).

    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.338 That report concluded that the United States' oil and gas “take” is among the lowest in the world.339 The second report, which focused on whether the Department of the Interior receives a fair return on the resources it manages, cited the “lack of price flexibility in royalty rates,” and the “inability to change fiscal terms on existing leases,” in support of a finding that the United States could be foregoing significant revenue from the production of onshore Federal oil and gas resources.340 Based on that finding, the second GAO report recommended that the U.S. Congress direct the Secretary of the Interior to convene an independent panel to review the Federal oil and gas fiscal system and establish procedures for periodic evaluation of the system going forward.

    338 GAO, Oil and Gas Royalties: A Comparison of the Share of Revenue Received from Oil and Gas Production by the Federal Government and Other Resource Owners, GAO 07 676R, May 2007.

    339 GAO-07-676R at 2.

    340 GAO-08-691 at 6.

    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”).341 The IHS CERA Study identified four factors amenable to comparison: Government take, internal rate of return, profit-investment ratio, and progressivity.342 The IHS CERA Study also considered measures of revenue risk and fiscal system stability. Overall, the IHS CERA Study found that, as of the time of the study, the Federal Government's fiscal system and overall take, in aggregate, were in the mainstream both nationally and internationally. Even within specific geographic regions, however, the IHS CERA Study estimated a wide range of government take, and its authors acknowledged that take varies with a variety of factors, including commodity prices, reserve size, reservoir characteristics, resource location, and water depth. As a result, the IHS CERA Study's authors favored a sliding-scale royalty system, because a sliding-scale royalty is more progressive than a fixed-rate royalty, and can also respond to changes in commodity market conditions.

    341 Agalliu, I. (2011). Comparative Assessment of the Federal Oil and Gas Fiscal Systems. U.S. Department of the Interior, Bureau of Ocean Energy Management, OCS Study, BOEM 2011-xxx, available at http://www.energy.senate.gov/public/index.cfm/files/serve?File_id=d174971c-4682-4d96-b194-a85fa2b86774.

    342 A “progressive” royalty rate refers to a rate that increases with the quantity of the resource being sold.

    In addition to the IHS CERA Study, the BLM also reviewed a separate study conducted by industry, the “Van Meurs Study.” 343 The Van Meurs Study looked at a range of jurisdictions and regions across North America and provided a comparison of the oil and gas fiscal systems on Federal, State, and private lands throughout the United States and the provinces in Canada. The Van Meurs Study suggested that as of 2011, Federal Government take on Federal lands was generally lower than the corresponding take on State or private lands. The Van Meurs Study also made several recommendations to State and Federal Governments in the United States and Canada, including that governments apply different fiscal terms to oil leases than to gas leases, based on the differing prices of oil and gas at the time the report was published.

    343 PFC Energy, Van Meurs Corporation, and Rodgers Oil & Gas Consulting (2011). World Rating of Oil and Gas Terms: Volume 1—Rating of North American Terms for Oil and Gas Wells with a Special Report on Shale Plays.

    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.344 The GAO acknowledged that actions had been taken in response to its prior recommendations, but remained concerned that the Department had not taken steps to change its onshore royalty rate regulations to provide flexibility with respect to fiscal terms for oil and gas leases.345

    344 GAO, Oil and Gas Resources—Actions Needed for Interior to Better Ensure a Fair Return, GAO-14-50, (Dec. 2013), 11.

    345 Ibid. At 23.

    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.346 In preparing the ANPR, the BLM gathered information about royalty rates charged by States and private mineral holders for oil and gas activities on State and private lands, and compared those rates to rates charged for Federal oil and gas resources. The data showed that the royalty rates charged on private and State lands range from 12.5 to 25 percent, and that the average rate assessed exceeds 16.67 percent.347

    346 80 FR 22148 (April 21, 2015).

    347 80 FR at 22151-52 (April 21, 2015).

    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 subsequent calendar year would increase by some increment (for example, 4 percent). In all other cases, the royalty rate would remain at, or revert to, the base rate specified in the lease.

    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.348 In that case, the additional regulatory language implementing a royalty adder could take the following form:

    348 See footnote 64.

    1. Amend § 3103.3-1(a)(2) to add the following subparagraphs:

    (iii) An additional 4 percent above the base rate on all competitively-issued leases for any calendar year in which the operator reported above-threshold flaring of associated gas during at least six of the 12 months preceding October 1st;

    (iv) The threshold flaring rate for purposes of paragraph (iii) is 300 Mcf/month multiplied by the number of wells on the lease that produced for at least 10 days during the month.

    (v) For communitized or unitized leases, the threshold flaring rate for purposes of paragraph (iii) is 300 Mcf/month multiplied by the sum of the number of stand-alone wells on the lease and the number of wells on each agreement from which the lease is receiving an allocation. To be counted, each well must have produced for at least 10 days during the relevant month. The flaring volume used to assess exceedance of the threshold will be determined using the same allocation formula that each agreement uses to allocate production to the lease under consideration.

    In this illustrative regulatory text, the royalty “adder” is 4 percent, and the threshold, de minimis flaring rate that would trigger application of the adder is 300 Mcf/producing well/month (or approximately 10 Mcf/producing well/day). Assuming the current base rate of 12.5 percent, a lease holder would continue to pay 12.5 percent for any year in which routine flaring of associated gas from its lease did not exceed the threshold rate during at least six of the 12 months preceding October 1st. On the other hand, any lease holder that reported above-threshold flaring of associated gas during at least 6 months of a calendar year would be obligated to pay a 16.5 percent royalty rate on all oil and gas production removed or sold from the lease during the subsequent calendar year. The rate would then revert back to 12.5 percent, for any year in which the lease holder reported at- or below-threshold flaring of associated gas during at least 6 of the 12 months preceding October 1st. Note that the 16.5 percent rate would be less than the average royalty rate that lease holders currently pay on oil and gas production removed or sold from onshore State and private leases (16.67 percent).349 As noted previously, this provision, if adopted in the final rule, would apply only to new competitively issued leases issued after the effective date of the rule, and would not apply to existing leases.

    349 80 FR at 22151-52 (April 21, 2015).

    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?

    D. Record Keeping Requirements

    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 specified timeframes. We are also soliciting comment on the most efficient and least burdensome means to make appropriate data available to the public.

    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.350

    350 Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9 at Section XVII.H.1.c. and XVII.F.8 for proposed §§ 3179.204 and 3179.305 respectively.

    E. Reporting and Information Availability

    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.

    F. Planning Process

    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,351 these commenters asked the BLM to use landscape-scale planning tools to complement the MLA waste prevention provisions.

    351See, e.g., Secretarial Order Nos. 3289 (Sept. 14, 2009) (updated by Amendment No. 1, Feb. 22, 2010) and 3226 (Jan. 19, 2001).

    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.352 They highlighted tools that allow the BLM to plan, manage for, and review the impacts of proposed actions before issuing leases or approving oil and gas development projects, in contrast to the “back end” application of specific technologies or practices to such projects.353 For example, these commenters suggested that by providing information to inform oil and gas development decisions, BLM inventories of the resource and other values of specific lands prepared under FLPMA Section 201(a) 354 could facilitate implementation and enforcement of the venting and flaring rule. They further suggested that by providing for public involvement, “front end” tools would facilitate public transparency and accountability and help to identify unexpected opportunities to prevent methane waste (such as in NEPA alternatives analyses).355

    352 Letter from the Western Environmental Law Center (WELC) et al. to Secretary Sally Jewell, DOI, Jan. 27, 2014, p. ii and Attached Core Principles, pp. 23-24 (hereinafter WELC Jan. 27 Letter).

    353 Letter from WELC et al. to Secretary Sally Jewell, DOI, May 30, 2014, Attached Comments, p. 11, n. 6 (hereinafter WELC May 30 Letter).

    354 43 U.S.C. 1711(a).

    355 WELC Jan. 27 Letter, p. 23.

    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.356 They also encouraged the BLM to use master leasing plans (MLP) “to establish front-end waste prevention goals” when planning for oil and gas development in a defined area and to identify specific best management practices or mitigation measures to prevent waste.357 These stakeholders argued that these and other tools would enable the BLM to “prevent methane waste at a broad basin- or field-level scale.” 358

    356 WELC Jan. 27 Letter, pp. 23-24; see also Letter from WELC and Clean Air Task Force to Director Neil Kornze, BLM, Dec. 5, 2014, pp. 2 and 4 (hereinafter WELC Dec. 5 Letter).

    357 WELC Jan. 27 Letter, p. 24.

    358 WELC May 30 Letter, pp. 11-12.

    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.359 These stakeholders also asked that the BLM “expressly coordinate its planning and management efforts with Federal, State, and local agencies that regulate downstream activities, as well as with industry segments responsible for downstream activities” to ensure that methane waste prevention actions are effective.360

    359 WELC Jan. 27 Letter, pp. 20-21; WELC May 30 Letter, pp. 21-22; WELC Dec. 5 Letter, p. 4 (urging the BLM to consider and require technologies and practices to prevent waste that are deemed reasonable in the context of basin- or field-specific conditions).

    360 WELC Jan. 27 Letter, p. 20.

    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.361

    361 GAO-11-34, 34.

    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.

    G. Facilities in Rights-of-Way

    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.362 Facilities located in rights-of-way include gas gathering and transmission pipelines and compressors, which are used to maintain pressure in the pipelines. Of these, it appears that compressors are likely to be the largest source of natural gas losses. Further, it appears that losses from sources located on rights-of-way could be addressed through available technologies and practices, such as LDAR programs.

    362 BLM Public Land Statistics, 2014 Table 3-4, column (c), Mineral Leasing Act.

    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 compressors only total about 1 percent of small compressor emissions in the U.S. according to the latest GHG Inventory.363 Given the limited impact of these rights-of-way facilities, and the fact that the BLM can already reach the facilities' emissions via conditions on rights-of-way, we are not proposing to address these facilities in this rulemaking. We request comment on this approach.

    363 BLM analysis of EPA GHG Inventory data applied against the estimated number of compressors located on BLM-managed ROW authorizations.

    H. State or Tribal Variances

    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.

    I. Section-by-Section Discussion 1. § 3103.3-1 Royalty on Production

    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.” 364

    364 See footnote 64.

    2. § 3160.0-5 Definitions

    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.

    3. § 3162.3-1 Drilling Applications and Plans

    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.

    4. Subpart 3178—Royalty-Free Use of Lease Production (a) § 3178.1 Purpose

    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.”

    (b) § 3178.2 Scope of This Subpart

    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.

    (c) § 3178.3 Production on Which Royalty Is Not Due

    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.

    (d) § 3178.4 Uses of Oil or Gas on a Lease, Unit, or CA That Do Not Require Prior Written BLM Approval for Royalty-Free Treatment of Volumes Used

    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 ensures that royalty-free on-site use remains subject to the requirement to avoid waste of the resource.

    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.

    (e) § 3178.5 Uses of Oil or Gas on a Lease, Unit, or CA That Require Prior Written BLM Approval for Royalty-Free Treatment of Volumes Used

    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:

    Using oil as a circulating medium in drilling operations. This use is expressly described as royalty-free under NTL-4A. Because using produced oil as a circulating medium is rare and creates a possibility of loss, the proposal would require that the BLM evaluate each request and approve the request in writing only when appropriate.

    Injecting gas produced from a lease, unit PA, or CA into the same lease, unit PA, or CA to increase the recovery of oil or gas. An operator must also obtain BLM approval for this use under existing regulations at 43 CFR 3162.3-2. The substance of this provision would not change from NTL-4A.

    Using oil or gas that was removed from the pipeline at a location downstream of the approved facility measurement point (FMP), provided that both removal and use occur on the lease, unit, or CA. The BLM anticipates that these situations would be quite rare because the tap that operators use to extract and measure gas is generally upstream of the FMP.

    Using produced gas for operations on the lease, unit PA, or CA, after it is returned from off-site treatment or processing to address a particular physical characteristic of the gas. Physical characteristics that might preclude initial use of gas in lease operations and necessitate off-lease treatment or processing include an unusually high concentration of hydrogen sulfide, or the presence of inert gases or liquid fractions that limit the gas's utility as a fuel. The operator would bear the burden of establishing the necessity of off-lease treatment; the BLM typically would not approve, as a royalty-free use, return of production to the lease for use in operations necessary to put production into marketable condition.

    Any other type of use that is consistent with proposed § 3178.3, but is not specifically identified in proposed § 3178.4. This provision would clarify that the BLM retains discretion to consider approving royalty-free use under circumstances that are not now anticipated.

    (f) § 3178.6 Uses of Oil or Gas Moved Off the Lease, Unit, or CA That Do Not Require Prior Written Approval for Royalty-Free Treatment of Volumes Used

    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 Plains Exploration & Production Co., “(t)he gas (is) not produced (extracted from the ground) until after it (has) crossed the lease line. Production and removal from the lease are both requisite to triggering the royalty obligation. . . . Thus, gas used in wellhead production operations would be regarded as used for the benefit of the lease.” 365

    365Plains Exploration & Production Co., 178 IBLA 327, 341 n.16 (2010).

    (g) § 3178.7 Uses of Oil or Gas Moved Off the Lease, Unit, or CA That Require Prior Written Approval for Royalty-Free Treatment of Volumes Used

    This proposed section would address the royalty treatment of oil or gas used in operations conducted off the lease, unit, or CA. When production is removed from the lease, unit, or CA, it becomes royalty-bearing unless otherwise provided. This principle is reflected in paragraph (a) of this proposed section, which would provide that with only limited exceptions, royalty is owed on all oil or gas used in operations conducted off the lease, unit, or CA (referred to here as “off-lease royalty-free use”).

    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 reflects the BLM's policy to encourage operators to reduce the amount of surface disturbance associated with oil and gas exploration and development projects. In some cases, centralizing production facilities at a location off the lease may serve that objective.

    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.” 366 The proposed section would add clarity and consistency in implementation.

    366 30 CFR 1202.150(b) (emphasis added).

    (h) § 3178.8 Measurement or Estimation of Royalty-Free Volumes

    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.367

    367 80 FR 40767 (July 13, 2015).

    For both oil and gas, the operator would have to report the volumes measured or estimated, as applicable, under ONRR requirements.

    (i) § 3178.9 Requesting Approval of Royalty-Free Treatment When Approval Is Required

    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.

    (j) § 3178.10 Facility and Equipment Ownership

    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.

    5. Subpart 3179—Waste Prevention and Resource Conservation (a) § 3179.1 Purpose

    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.

    (b) § 3179.2 Scope of This Subpart

    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.

    (c) § 3179.3 Definitions and Acronyms

    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.

    (d) § 3179.4 Determining When the Loss of Oil or Gas Is Avoidable or Unavoidable

    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 comply with the limits of proposed § 3179.6.

    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.”

    (e) § 3179.5 When Lost Production Is Subject to Royalty

    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.

    (f) § 3179.6 When Flaring or Venting Is Prohibited

    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.

    (g) § 3179.7 Alternative Limits on Venting and Flaring

    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.

    (h) § 3179.8 Measuring and Reporting Volumes of Gas Vented and Flared From Wells

    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.368

    368 Estimation in this instance involves the use of known well or reservoir information such as periodic well tests or a well's gas to oil ratio to estimate a well's gas production rate. For example, if a production flow test is conducted monthly on a well, one might presume the well continued producing gas at the tested rate for the entire month. Similarly, if a well has a gas to oil ratio that is uniform over time, the operator could estimate the rate of gas production based on the measured rate of oil production and the gas to oil ratio. Gas volume estimation using these protocols is suitable for reporting flared gas volumes in many cases.

    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.369

    369 For oil: Onshore Oil and Gas Order No. 4, III(C), III(D), and III(E); for gas: Onshore Oil and Gas Order No. 5, III(C) and III(D). More information can be found at http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/onshore_oil_and_gas.html.

    This proposed section would also require operators to report all volumes vented or flared under applicable ONRR reporting requirements.

    (i) § 3179.9 Determinations Regarding Royalty-Free Venting or Flaring

    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.

    (j) § 3179.10 Other Waste Prevention Measures

    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.370 Specifically, if production from a new well would force an existing producing well already connected to the pipeline to go offline, then notwithstanding the requirements in 3179.6 and 3179.7, the BLM could limit the volume of production from the new well for a period of time, while gas pressures from the new well stabilize. In addition, the BLM could delay action on an APD or approve it with conditions related to gas capture and production levels. The BLM could suspend the lease under 43 CFR 3103.4-4 if the lease associated with the APD is not in producing status.

    370 30 U.S.C. 187; 30 U.S.C. 225.

    (k) § 3179.11 Coordination With State Regulatory Authority

    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.

    6. Flaring and Venting Gas During Drilling and Production Operations (a) § 3179.101 Well Drilling

    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.

    (b) § 3179.102 Well Completion and Related Operations

    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.

    (c) § 3179.103 Initial Production Testing

    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.

    (d) § 3179.104 Subsequent Well Tests

    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.

    (e) § 3179.105 Emergencies

    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.

    7. Gas Flared or Vented From Equipment or During Well Maintenance Operations (a) § 3179.201 Equipment Requirements for Pneumatic Controllers

    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 regulations that prohibit the new use of high-bleed pneumatic controllers (40 CFR 60.5360 through 60.5390).

    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.

    (b) § 3179.202 Requirements for Pneumatic Chemical Injection Pumps or Pneumatic Diaphragm Pumps

    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.

    (c) § 3179.203 Crude Oil and Condensate Storage Vessels

    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.

    (d) § 3179.204 Downhole Well Maintenance and Liquids Unloading

    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.

    8. Leak Detection and Repair (a) § 3179.301 Operator Responsibility

    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.

    (b) § 3179.302 Approved Instruments and Methods

    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.

    (c) § 3179.303 Leak Detection Inspection Requirements for Natural Gas Wellhead Equipment, Facilities, and Compressors

    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.

    (d) § 3179.304 Repairing Leaks

    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.

    (e) § 3179.305 Leak Detection Inspection Recordkeeping

    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.

    9. State or Tribal Variances (a) § 3179.401 State or Tribal Requests for Variances From the Requirements of This Subpart

    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.

    VI. Analysis of Impacts A. Description of the Regulated Entities 1. Potentially Affected Entities

    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.371 We believe that these 1,828 entities would be most affected by the proposed rule, in addition to entities currently involved with drilling and support activities, and any entities that become involved in the future.

    371 The actual number is expected to be slightly lower due to duplicate entries.

    The potentially affected entities are likely to fall within one of the following industries, identified by the North American Industry Classification System (NAICS) codes:

    • NAICS Code 21111 “Oil and Gas Extraction” • NAICS Code 213111 “Drilling Oil and Gas Wells” • NAICS Code 213112 “Support Activities”

    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.372 First, the table identifies the total number of entities within each industry and the number of entities with less than 500 employees and the number of entities with 500 or more employees. Next, the table identifies the total employment within each industry and the combined employment for entities with less than 500 employees and the combined employment for entities with 500 or more employees. Third, the table shows the total annual payroll for each industry and the combined annual payroll for entities with less than 500 employees and the combined annual payroll for entities with 500 or more employees.

    372 Calendar year 2011 is the most recent data available from the U.S. Census Bureau that includes detailed employment data. Entities primarily involved in the support of mining activities on a contract basis were not included in this count.

    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 373 represent an upper bound estimate of the operators that could potentially be affected by this rulemaking.

    373 U.S. Census Bureau data does not readily differentiate between the number of firms involved in oil development and production activities versus gas development and production.

    2. Affected Small Entities

    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.374

    374 U.S. Census Bureau does not provide receipt data that allow a break at the $38.5 million threshold as defined by SBA. As such, the 97 percent figure is a slight underestimate.

    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.

    B. Impacts of the Proposed Requirements 1. Overall Costs of the Rule 375

    375 RIA at 81-90.

    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.376 These costs include engineering compliance costs and the social cost of minor additions of carbon dioxide to the atmosphere.377 The engineering compliance costs presented do not include potential cost savings from the recovery and sale of natural gas (those savings are shown in the summary of benefits).

    376 RIA at 127.

    377 Some gas that would have otherwise been vented would now be combusted on-site or presumably downstream to generate electricity. The estimated value of the carbon additions do not exceed $21,000 in any given year.

    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.378

    378 RIA at 127.

    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.

    2. Overall Benefits of the Rule 379

    379 RIA at 85-90.

    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 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).380 We estimate that the proposed rule would reduce methane emissions by 164,000-169,000 tpy, which we estimate to be worth $180-253 million per year (this social benefit is included in the monetized benefit above). We estimate that the proposed rule would reduce VOC emissions by 391,000-411,000 (this benefit is not monetized in our calculations).381

    380 RIA at 130.

    381 RIA at 133-135.

    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).382 We estimate that the proposed rule would reduce methane emissions by 176,000-185,000 tpy, which we estimate to be $193-277 million per year (this social benefit is included in the monetized benefit above). We estimate that the proposed rule would reduce VOC emissions by 400,000-423,000 (this benefit is not monetized in our calculations).383

    382 RIA at 130.

    383 RIA at 133-135.

    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.

    3. Net Benefits of the Proposed Rule

    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 2025-2026.384

    384 RIA at 67.

    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).

    4. Distributional Impacts

    (a) Energy Systems 385

    385 RIA at 92-93.

    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 2013.386

    386 RIA at 140.

    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 2013.387

    387 RIA at 140.

    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.

    (b) Royalties 388

    388 RIA at 94-95.

    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 389

    389 The BLM conducted an Initial Regulatory Flexibility Analysis, RIA at 154-166.

    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 390 for the years 2012, 2013 and 2014. We then calculated a profit margin figure for each company when subject to the average annual cost increase associated with this rule. For simplicity, we used the average per-entity cost increase figures of $31,400 and $37,600 which roughly represent the middle of the range of potential per-entity costs assuming the EPA finalizes and does not finalize subpart OOOOa, respectively. Both figures include compliance costs and cost savings, calculated using a 7 percent discount rate.

    390 The profit margin was calculated by dividing the net income by the total revenue as reported in the companies' 10-K filings.

    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.

    (d) Employment 391

    391 RIA at 148.

    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.” 392 An analysis of employment impacts is a standalone analysis and the impacts should not be included in the estimation of benefits and costs.

    392 Executive Order 13563, Improving Regulation and Regulatory Review (Jan. 18, 2011).

    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.

    (e) Impacts on Tribal Lands 393

    393 RIA at 148-150.

    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).394

    394 RIA at 148.

    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).395

    395 Ibid.

    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).396

    396 Ibid.

    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.397 We further estimate that the proposed rule would reduce methane emissions from leases on Indian lands by 20,000 tpy, and would reduce VOC emissions by 48,000-51,000 tpy.398

    397 RIA at 150.

    398 RIA at 149.

    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 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 further estimate that the proposed rule would reduce methane emissions from leases on Indian lands by 22,000-23,000 tpy, and would reduce VOC emissions by 50,000-53,000 tpy.

    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.

    VII. Procedural Matters A. Executive Order 12866, Regulatory Planning and Review  399

    399 RIA at 167.

    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.

    B. Regulatory Flexibility Act and Small Business Regulatory Enforcement Fairness Act of 1996  400

    400 RIA at 167-168.

    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.401 Congress enacted the RFA to ensure that government regulations do not unnecessarily or disproportionately burden small entities. Small entities include small businesses, small governmental jurisdictions, and small not-for-profit enterprises.

    401 5 U.S.C. 601-612. The exception is found in 5 U.S.C. 605(b).

    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.402 There are several factors driving this decision. First, although the projected costs are expected to be quite small, as a percentage of a typical firm's annual profits, there is significant uncertainty associated with these costs. There is a combination of factors contributing to the uncertainty associated with the costs of this rule. These factors include limited data, a wide range of possible variation in commodity prices over time, and a variety of possible compliance options, particularly with respect to the flaring requirements. In addition, the BLM is taking comment on a wide range of alternatives to some of the proposed requirements, and some of these alternatives could affect the costs of the rule if the BLM were to adopt them in the final rule. This further enhances the uncertainty regarding the cost projections for the rule. Second, there is no question that if the costs of the rule for affected entities were economically significant, the BLM would be required to prepare an IRFA for the rule, given that the rule will affect a substantial number of small entities.

    402 See RIA, section 9.

    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.

    C. Unfunded Mandates Reform Act of 1995

    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.

    D. Executive Order 12630, Governmental Actions and Interference With Constitutionally Protected Property Rights (Takings)

    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 under which gas can be flared or vented, and under which an operator can use oil and gas on a lease, unit, or communitized area for operations and production purposes, without paying royalty.

    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.

    E. Executive Order 13132, Federalism

    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.

    F. Executive Order 12988, Civil Justice Reform

    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.

    G. Executive Order 13175, Consultation and Coordination With Indian Tribal Governments

    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).403 At the Denver and Washington, DC sessions, the tribal meetings were live-streamed to allow for the greatest possible participation by tribes and others. The tribal outreach sessions served as initial consultation with Indian tribes to comply with Executive Order 13175. We look forward to continuing close interaction with tribal regulators as we proceed through this rulemaking process.

    403 More info can be found at: http://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.html

    H. Paperwork Reduction Act 1. Overview

    The Paperwork Reduction Act (PRA) 404 provides that an agency may not conduct or sponsor, and a person is not required to respond to, a “collection of information,” unless it displays a currently valid control number. Collections of information include any request or requirement that persons obtain, maintain, retain, or report information to an agency, or disclose information to a third party or to the public.405

    404 44 U.S.C. 3501-3521.

    405 44 U.S.C. 3502(3); 5 CFR 1320.3(c).

    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 [email protected] or by telephone request to 202-912-7311. You may also review the information collection request online at: http://www.reginfo.gov/public/do/PRAMain.

    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 ADDRESSES section of this preamble. Please identify your comments with “OMB Control Number 1004-XXXX.” OMB is required to make a decision concerning the collection of information contained in this proposed rule between 30 to 60 days after publication of this document in the Federal Register. Therefore, a comment to OMB is best assured of having its full effect if OMB receives it by March 9, 2016.

    2. Summary of Proposed Information Collection Requirements

    • 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.

    3. Proposals Involving APDs and Sundry Notices (a) Plan to Minimize Waste of Natural Gas (Form 3160-3) (43 CFR 3162.3-1(j))

    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).

    (b) Request for Prior Approval for Royalty-Free Uses On-Lease or Off-Lease (43 CFR 3178.5, 3178.7, and 3178.9)

    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 (e.g., equipment manufacturer's published consumption or usage rates); and

    • The proposed disposition of the oil or gas used (e.g., whether gas used would be consumed as fuel, vented through use of a gas-activated pneumatic controller, returned to the reservoir, or some other disposition).

    (c) Request for Approval of Alternative Volume Limits (43 CFR 3179.7)

    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 (i.e., heating value and H2S content), revenues derived from gas production, and royalty payments on gas production over the next 15 years or the life of each of the operator's leases, units, or CAs, whichever is less; and

    • 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.

    (d) Certification in Support of Exemption From Volume Limits (43 CFR 3179.7(d))

    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.

    (e) Well Completion and Related Operations (43 CFR 3179.102(b))

    • 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).

    (f) Initial Production Testing Request for Extension (43 CFR 3179.103)

    • 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.

    (g) Subsequent Well Tests Request for Extension (43 CFR 3179.104)

    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)

    (h) Reporting of Emergency Venting or 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.

    (i) Pneumatic Controller Report (43 CFR 3179.201(b) and (c))

    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.

    (j) Pneumatic Pump Report (43 CFR 3179.202)

    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.

    (k) Crude Oil and Condensate Storage Vessels (43 CFR 3179.203(c))

    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.

    (l) Downhole Well Maintenance and Liquids Unloading—Documentation and Reporting (43 CFR 3179.204(a) and (d))

    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.

    4. Other Proposed Information Collection Activities (a) Downhole Well Maintenance and Liquids Unloading—Notice of Excessive Duration or Volume (43 CFR 3179.204(e)

    Proposed § 3179.204 would pertain to downhole well maintenance and liquids unloading operations. Paragraph (e) would require an operator to notify the BLM in a Sundry Notice within 14 days if the cumulative duration of well purging events for a well exceeds 24 hours during any production month, or if the estimated gas volume vented in liquids unloading by well purging operations for a well exceed 75 Mcf during any production month.

    (b) Leak Detection Inspection and Repair

    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.

    5. Burden Estimates

    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.

    Proposals Involving APDs and Sundry Notices Estimated Hour Burdens Type of response Number of
  • responses
  • Hours per
  • response
  • Total Hours
  • (column B × column C)
  • A. B. C. D. Plan to Minimize Waste of Natural Gas, 43 CFR 3162.3-1, Form 3160-3 2,000 2 4,000 Request for Prior Approval for Royalty-Free Uses On-Lease or Off-Lease, 43 CFR 3178.5, 3178.7, and 3178.9, Form 3160-5 50 8 400 Request for Approval of Alternative Volume Limits, 43 CFR 3179.7(b), Form 3160-5 185 16 2,960 Certification in Support of Exemption from Volume Limits, 43 CFR 3179.7(d), Form 3160-5 15 16 240 Well Completion and Related Operations, 43 CFR 3179.102(b), Form 3160-5 5 2 10 Initial Production Testing Request for Extension, 43 CFR 3179.103, Form 3160-5 5 2 10 Subsequent Well Tests Request for Extension, 43 CFR 3179.104, Form 3160-5 5 2 10 Reporting of Emergency Venting and Flaring Beyond Specified Timeframes, 43 CFR 3179.105, Form 3160-5 25 2 50 Pneumatic Controller Report, 43 CFR 3179.201(b) and (c), Form 3160-5 200 2 400 Pneumatic Pump Report, 43 CFR 3179.202, Form 3160-5 250 8 2,000 Crude Oil and Condensate Storage Vessels, 43 CFR 3179.203(c), Form 3160-5 100 8 800 Downhole Well Maintenance and Liquids Unloading—Documentation and Reporting, 43 CFR 3179.204(a) and (d), Form 3160-5 5,000 1 5,000 Downhole Well Maintenance and Liquids Unloading—Notification of Excessive Duration or Volume, 43 CFR 3179.204(e)
  • Form 3160-5
  • 120 1 120
    Leak Detection—Compliance with EPA Regulations, 43 CFR 3179.301(e), Form 3160-5 500 8 4,000 Leak Detection—Request to Use and Alternative Device, Program, or Method, 43 CFR 3179.303(b), Form 3160-5 200 40 8,000 Leak Detection—Notification of Delay in Repairing Leaks, 43 CFR 3179.304(a), Form 3160-5 100 1 100 Totals 8,760 28,100

    The following table details the annual estimated hour burdens for the rest of the proposed information collection activities in this rule.

    Estimated Annual Hour Burdens for Other IC Activities Type of response Number of
  • responses
  • Hours per
  • response
  • Total Hours
  • (column B × column C)
  • A. B. C. D. Downhole Well Maintenance and Liquids Unloading—Recordkeeping, 43 CFR 3179.204(c) 5,000 0.25 1,250 Leak Detection—Inspection Recordkeeping, 43 CFR 3179.305 52,000 .25 13,000 Totals 57,000 14,250
    I. National Environmental Policy Act

    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” under section 102(2)(C) of the National Environmental Policy Act (NEPA).406 The BLM believes that, for the most part, the proposed rule would benefit the environment by reducing emissions of methane (a potent GHG), VOCs (which contribute to smog), and hazardous air pollutants such as benzene (a known carcinogen). In addition, the proposed rule would reduce light pollution and other impacts from flaring. The rule may also have indirect and minor to negligible adverse environmental impacts, primarily due to land disturbance from increased or accelerated construction of gas pipelines and compressors and/or increased truck traffic on existing disturbed surfaces from the increased use of mobile capture technology. In the aggregate, the beneficial impacts of the proposed rule are expected to dwarf its adverse impacts. Further, the BLM anticipates that any new gathering lines would be subject to additional environmental review based on submission of a Sundry Notice or a FLPMA Title V right-of-way application prior to construction.

    406 42 U.S.C. 4332(2)(C).

    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 www.regulations.gov (use the search term 1004-AE14, open the Docket Folder, and look under Supporting Documents) and at the address specified in the ADDRESSES section.

    J. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

    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 Federal Register) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1)(i) that is a significant regulatory action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by the Administrator of (OIRA) as a significant energy action.”

    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.

    K. Clarity of the Regulations

    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 SUPPLEMENTARY INFORMATION section of this preamble helpful in understanding the proposed regulations? How could this description be more helpful in making the proposed regulations easier to understand?

    Please send any comments you have on the clarity of the regulations to the address specified in the ADDRESSES section.

    L. Executive Order 13563, Improving Regulation and Regulatory Review

    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.

    VIII. Authors

    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.

    List of Subjects 43 CFR Part 3100

    Government contracts, Mineral royalties, Oil and gas reserves, Public lands-mineral resources, Reporting and recordkeeping requirements, Surety bonds.

    43 CFR Part 3160

    Administrative practice and procedure, Government contracts, Indians-lands, Mineral royalties, Oil and gas exploration, Penalties, Public lands—mineral resources, Reporting and recordkeeping requirements.

    43 CFR Part 3170

    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.

    Dated: January 21, 2016. Janice M. Schneider, Assistant Secretary, Land and Minerals Management.

    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:

    PART 3100—ONSHORE OIL AND GAS LEASING 1. Revise the authority citation for part 3100 to read as follows: Authority:

    25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359 and 1751; 43 U.S.C. 1732(b), 1733, and 1740; and the Energy Policy Act of 2005 (Pub. L. 109-58).

    2. Revise § 3103.3-1 to read as follows:
    § 3103.3-1 Royalty on production.

    (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) 121/2 percent on all noncompetitive leases; and

    (ii) A base rate of not less than 121/2 percent on all competitive leases, exchange and renewal leases, and leases issued in lieu of unpatented oil placer mining claims under § 3108.2-4;

    (3) 16 2/3 percent on noncompetitive leases reinstated under § 3108.2-3 plus an additional 2 percentage-point increase added for each succeeding reinstatement; and

    (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 121/2 percent royalty rate.

    (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.

    PART 3160—ONSHORE OIL AND GAS OPERATIONS 3. The authority citation for part 3160 continues to read as follows: Authority:

    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.

    § 3160.0-5 [Amended]
    4. Amend § 3160.0-5 by removing the definition of “Avoidably lost.” 5. Amend § 3162.3-1 by adding paragraph (j) to read as follows:
    § 3162.3-1 Drilling applications and plans.

    (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.

    PART 3170—ONSHORE OIL AND GAS PRODUCTION 6. The authority citation for part 3170, which was proposed to be added on July 13, 2015 (80 FR 40768), continues to read as follows: Authority:

    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.

    7. Add subparts 3178 and 3179 to part 3170, which was proposed to be added on July 13, 2015 (80 FR 40768), to read as follows: Subpart 3178—Royalty-Free Use of Lease Production Sec. 3178.1 Purpose. 3178.2 Scope. 3178.3 Production on which a royalty is not due. 3178.4 Uses of oil or gas on lease, unit, or CA that do not require prior written BLM approval for royalty-free treatment of volumes used. 3178.5 Uses of oil or gas on a lease, unit, or CA that require prior written BLM approval for royalty-free treatment of volumes used. 3178.6 Uses of oil or gas moved off the lease, unit, or CA that do not require prior written approval for royalty-free treatment of volumes used. 3178.7 Uses of oil or gas moved off the lease, unit, or CA that require prior written approval for royalty-free treatment of volumes used. 3178.8 Measurement or estimation of royalty-free volumes. 3178.9 Requesting approval of royalty-free treatment when approval is required. 3178.10 Facility and equipment ownership. Subpart 3179—Waste Prevention and Resource Conservation Sec. 3179.1 Purpose. 3179.2 Scope. 3179.3 Definitions and acronyms. 3179.4 Determining when the loss of oil or gas is avoidable or unavoidable. 3179.5 When lost production is subject to royalty. 3179.6 When flaring or venting is prohibited. 3179.7 Alternative limits on venting and flaring. 3179.8 Measuring and reporting volumes of gas vented and flared from wells. 3179.9 Determinations regarding royalty-free venting or flaring. 3179.10 Other waste-prevention measures. 3179.11 Coordination with State regulatory authority. Flaring and Venting Gas During Drilling and Production Operations 3179.101 Well drilling. 3179.102 Well completion and related operations. 3179.103 Initial production testing. 3179.104 Subsequent well tests. 3179.105 Emergencies. Gas Flared or Vented From Equipment During Well Maintenance Operations 3179.201 Equipment requirements for pneumatic controllers. 3179.202 Requirements for pneumatic chemical injection pumps or pneumatic diaphragm pumps. 3179.203 Crude oil and condensate storage vessels. 3179.204 Downhole well maintenance and liquids unloading. Leak Detection and Repair (LDAR) 3179.301 Operator responsibility. 3179.302 Approved instruments and methods. 3179.303 Leak detection and inspection requirements for natural gas wellhead equipment, facilities, and compressors. 3179.304 Repairing leaks. 3179.305 Leak detection inspection recordkeeping. State or Tribal Variances 3179.401 State or tribal requests for variances from the requirements of this subpart.
    § 3178.1 Purpose.

    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.

    § 3178.2 Scope.

    (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.

    § 3178.3 Production on which royalty is not due.

    (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.

    § 3178.4 Uses of oil or gas on a lease, unit, or CA that do not require prior written BLM approval for royalty-free treatment of volumes used.

    (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, e.g., hot oil treatment. The operator must document the removal of the oil from the tank or pipeline under Onshore Oil and Gas Order No. 3 (Site Security), or any successor regulation.

    (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.

    § 3178.5 Uses of oil or gas on a lease, unit, or CA that require prior written BLM approval for royalty-free treatment of volumes used.

    (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 Oil and Gas Orders No. 4 (oil) and 5 (gas) as applicable, or other successor regulations.

    (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.

    § 3178.6 Uses of oil or gas moved off the lease, unit, or CA that do not require prior written approval for royalty-free treatment of volumes used.

    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.

    § 3178.7 Uses of oil or gas moved off the lease, unit, or CA that require prior written approval for royalty-free treatment of volumes used.

    (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.

    § 3178.8 Measurement or estimation of royalty-free volumes.

    (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.

    § 3178.9 Requesting approval of royalty-free treatment when approval is required.

    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 (e.g., equipment manufacturer's published consumption or usage rates); and

    (d) The proposed disposition of the oil or gas used (e.g., whether gas used would be consumed as fuel, vented through use of a gas-activated pneumatic controller, returned to the reservoir, or some other disposition).

    § 3178.10 Facility and equipment ownership.

    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.

    Subpart 3179—Waste Prevention and Resource Conservation
    § 3179.1 Purpose.

    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.

    § 3179.2 Scope.

    (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 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.

    § 3179.3 Definitions and acronyms.

    As used in this subpart, the term:

    Accessible component means a component that can be reached, if necessary, by safe and proper use of portable ladders or by built-in ladders and walkways. Accessible components also include components that can be reached by the safe use of an extension on a monitoring probe.

    Capture means the physical containment of natural gas for transportation to market or productive use of natural gas, and includes reinjection and royalty-free on-site uses pursuant to subpart 3178.

    Capture infrastructure means any pipelines, facilities, or other equipment (including temporary or mobile equipment) used to capture, transport, or process gas. Capture infrastructure includes, but is not limited to, equipment that compresses or liquefies natural gas, removes natural gas liquids, or generates electricity from gas.

    Component means any piece of equipment that has the potential to leak gas and can be tested in the manner described in §§ 3179.301 through 3179.305 of this subpart.

    Development oil well or development gas well means a well drilled to produce oil or gas, respectively, from an established field in which hydrocarbons have been discovered and are being produced at a profit or expected profit. For purposes of this subpart, the BLM will determine when a well is a development oil well or development gas well in the event of a disagreement between the BLM and the operator.

    Gas-to-oil ratio (GOR) means the ratio of gas to oil in the production stream expressed in standard cubic feet of gas per barrel of oil.

    Gas well means a well for which the energy equivalent of the gas produced, including its entrained liquefiable hydrocarbons, exceeds the energy equivalent of the oil produced. Unless more specific British thermal unit (Btu) values are available, a well with a gas-to-oil ratio greater than 6 thousand cubic feet (Mcf) of gas per barrel of oil is a gas well. Except where gas has been re-injected into the reservoir, a mature oil well would not be reclassified as a gas well even after normal production decline has caused the GOR to increase beyond 6 Mcf of gas per barrel of oil.

    Liquid hydrocarbon means chemical compounds of hydrogen and carbon atoms that exist as a liquid under the temperature and pressure at which they are measured. The term is used to refer to oil, condensate, liquefied petroleum gas (LPG), liquefied natural gas (LNG), and natural gas liquids (NGL).

    Liquids unloading means the removal of an accumulation of liquid hydrocarbons or water in the wellbore of a completed gas well.

    Lost oil or lost gas means produced oil or gas that escapes containment, either intentionally or unintentionally, or is flared before being removed from the lease, unit, or CA, and cannot be recovered.

    Storage vessel means a crude oil or condensate storage tank or battery of tanks that vents, or is designed to vent, to the atmosphere during normal operations.

    Volatile organic compounds (VOC) has the same meaning as defined in 40 CFR 51.100(s).

    § 3179.4 Determining when the loss of oil or gas is avoidable or unavoidable.

    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.

    § 3179.5 When lost production is subject to royalty.

    (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.

    § 3179.6 When flaring or venting is prohibited.

    (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.

    § 3179.7 Alternative limits on venting and flaring.

    (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 operator demonstrates, and the BLM agrees, that the applicable limit under § 3179.6 would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease.

    (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 (i.e., heating value and H2S content), revenues derived from gas production, and royalty payments on gas production over the next 15 years or the life of the operator's lease, unit, or CA, whichever is less; and

    (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.

    § 3179.8 Measuring and reporting volumes of gas vented and flared from wells.

    (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.

    § 3179.9 Determinations regarding royalty-free venting or flaring.

    (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].

    § 3179.10 Other waste prevention measures.

    (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.

    § 3179.11 Coordination with State regulatory authority.

    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.

    Flaring and Venting Gas During Drilling and Production Operations
    § 3179.101 Well drilling.

    (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 control is due to operator negligence. The BLM will notify the operator in writing when it makes a determination that gas was lost due to operator negligence.

    § 3179.102 Well completion and related operations.

    (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.

    § 3179.103 Initial production testing.

    (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.

    § 3179.104 Subsequent well tests.

    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.

    § 3179.105 Emergencies.

    (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.

    Gas Flared or Vented From Equipment or During Well Maintenance Operations
    § 3179.201 Equipment requirements for pneumatic controllers.

    (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.

    § 3179.202 Requirements for pneumatic chemical injection pumps or pneumatic diaphragm pumps.

    (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, based on the information identified in § 3179.7(b), that installation of a zero-emissions pump(s) would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease; and

    (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.

    § 3179.203 Crude oil and condensate storage vessels.

    (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.

    § 3179.204 Downhole well maintenance and liquids unloading.

    (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.

    Leak Detection and Repair (LDAR)
    § 3179.301 Operator responsibility.

    (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.

    § 3179.302 Approved instruments and methods.

    (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.

    § 3179.303 Leak detection inspection requirements for natural gas wellhead equipment, facilities, and compressors.

    (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.

    If the operator inspects And in two consecutive inspections the operator The operator (1) Semi-annually Detects no more than 2 leaks at the site inspected Must inspect at least annually. (2) Annually Detects 3 or more leaks at the site inspected Must inspect at least semi-annually. (3) Semi-annually Detects 3 or more leaks at the site inspected Must inspect at least quarterly. (4) Quarterly Detects no more than 2 leaks at the site inspected Must inspect at least semi-annually.

    (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.

    § 3179.304 Repairing leaks.

    (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.

    § 3179.305 Leak detection inspection recordkeeping.

    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.

    State or Tribal Variances
    § 3179.401 State or tribal requests for variances from the requirements 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.

    [FR Doc. 2016-01865 Filed 2-5-16; 8:45 am] BILLING CODE 4310-84-P
    81 25 Monday, February 8, 2016 Rules and Regulations Part III Environmental Protection Agency 40 CFR Part 241 Additions to List of Categorical Non-Waste Fuels; Final Rule ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 241 [EPA-HQ-RCRA-2013-0110; FRL-9929-56-OLEM] RIN-2050-AG74 Additions to List of Categorical Non-Waste Fuels AGENCY:

    Environmental Protection Agency (EPA).

    ACTION:

    Final rule.

    SUMMARY:

    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 (e.g. oil delivery mechanisms are removed) in order to use natural gas instead of fuel oil, as part of normal operations and not solely as part of start-up or shut-down operations.

    DATES:

    This rule is effective March 9, 2016.

    ADDRESSES:

    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 http://www.regulations.gov Web site. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically at http://www.regulations.gov or in hard copy at the RCRA Docket, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave. NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m. Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the RCRA Docket is (202) 566-0270.

    FOR FURTHER INFORMATION CONTACT:

    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: [email protected].

    SUPPLEMENTARY INFORMATION:

    The information presented in this preamble is organized as follows:

    I. General Information A. Does this action apply to me? B. Why is the EPA taking this action? II. Statutory Authority III. Introduction-Summary of Regulations Being Finalized IV. Background A. History of the NHSM Rulemakings B. Background to Final Rule C. How does the EPA make categorical non-waste determinations? V. Comments on the Proposed Rule and Rationale for Final Decisions A. Construction and Demolition Debris Processed According to Best Management Practices 1. Detailed Description of C&D Wood 2. C&D Wood Under Current NHSM Rules 3. Scope of the Proposed Rule and Final Categorical Non-Waste Listing for C&D Wood 4. Rationale for Final Rule 5. Summary of Comments Requested 6. Response to Comments B. Paper Recycling Residuals Used as Fuel at Paper Recycling Mills 1. Detailed Description of Paper Recycling Residuals 2. PRRs Under Previous NHSM Rules 3. Scope of the Proposed Rule and Final Categorical Non-Waste Listing for Certain PRRs 4. Rationale for Final Rule 5. Summary of Comments Requested 6. Responses to Comments C. Creosote-Treated Railroad Ties (CTRTs) 1. Detailed Description of CTRTs 2. CTRTs Under Previous NHSM Rules 3. Scope of the Proposed Rule and Final Categorical Non-Waste Listing for CTRT 4. Rationale for Final Rule 5. Summary of Comments Requested 6. Responses to Comments VI. Technical Corrections A. Change to 40 CFR 241.3(b)(2) B. Change to 40 CFR 241.3(c)(1) C. Change to 40 CFR 241.3(d)(1)(iii) VII. Effect of This Rule on Other Programs VIII. State Authority A. Relationship to State Programs B. State Adoption of the Rulemaking IX. Cost and Benefits X. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations K. Congressional Review Act (CRA) I. General Information A. Does this action apply to me?

    Categories and entities potentially affected by this action, either directly or indirectly, include, but may not be limited to the following:

    Generators and Potential Users  a of the New Materials To Be Added to the List of Categorical Non-Waste Fuels Primary industry category or sub category NAICS b Utilities 221 Construction of Buildings 236 Site Preparation Contractors 238910 Manufacturing 31, 32, 33 Wood Product Manufacturing 321 Sawmills 321113 Wood Preservation (includes crosstie creosote treating) 321114 Pulp, Paper, and Paper Products 322 Cement manufacturing 32731 Railroads (includes line haul and short line) 482 Scenic and Sightseeing Transportation, Land (Includes: Railroad, scenic and sightseeing) 487110 Port and Harbor Operations (Used railroad ties) 488310 Landscaping Services 561730 Solid Waste Collection 562111 Solid Waste Landfill 562212 Solid Waste Combustors and Incinerators 562213 Marinas 713930 a Includes: Major Source Boilers, Area Source Boilers, and Solid Waste Incinerators. b NAICS—North American Industrial Classification System.

    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 FOR FURTHER INFORMATION CONTACT section.

    B. Why is the EPA taking this action?

    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.

    Abbreviations and Acronyms. The following acronyms and abbreviations are used in this document.

    ATCM Airborne Toxic Control Measure BMP Best management practice Btu British thermal unit C&D Construction and demolition CAA Clean Air Act CARB California Air Resources Board CBI Confidential business information CCA Chromated copper arsenate CFR Code of Federal Regulations CISWI Commercial and Industrial Solid Waste Incinerator CTRT Cresosote-treated railroad tie EPA U.S. Environmental Protection Agency FR Federal Register HAP Hazardous air pollutant ICR Information collection request MACT Maximum achievable control technology NAICS North American Industrial Classification System ND Non-detect NESHAP National emission standards for hazardous air pollutants NHSM Non-hazardous secondary material OCC Old Corrugated Cardboard OMB Office of Management and Budget PAH Polycyclic aromatic hydrocarbons ppm Parts per million PRR Paper recycling residual PVC Polyvinyl chloride RCRA Resource Conservation and Recovery Act RIN Regulatory information number SBA Small Business Administration SO2 Sulfur dioxide SVOC Semi-volatile organic compound TCLP Toxicity characteristic leaching procedure UMRA Unfunded Mandates Reform Act UPL Upper prediction limit U.S.C. United States Code VOC Volatile organic compound XRF X-ray fluorescence II. Statutory Authority

    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).

    III. Introduction-Summary of Regulations Being Finalized

    Regulations concerning NHSMs used as fuels or ingredients in combustion units are codified in 40 CFR part 241.1 This action amends the part 241 regulations by adding three NHSMs to the list of categorical non-waste fuels codified in § 241.4(a). These new categorical listings are for:

    1 40 CFR 241.2 defines non-hazardous secondary material as a secondary material that, when discarded, would not be identified as a hazardous waste under 40 CFR part 261.

    • Construction and demolition (C&D) wood processed from C&D 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.

    • 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 2 subject to 40 CFR part 63, subpart DDDDD that combust CTRT and had been designed to burn biomass and fuel oil, but are modified (e.g. oil delivery mechanisms were removed) in order to use natural gas instead of fuel oil, as part of normal operations and not solely as part of start-up or shut-down operations.

    2 40 CFR 241.2 defines power producer as a boiler unit producing electricity for sale to the grid. The term does not include units meeting the definition of electricity generating unit under 40 CFR 63.10042 of the Utility Mercury and Air Toxics Standards rule.

    (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.” Id at 7429(g)(6). The Solid Waste Disposal Act, as amended, is commonly referred to as the Resource Conservation and Recovery Act or RCRA. If a material is a solid waste under RCRA, a combustion unit burning that material is required to meet the CAA section 129 emission standards for solid waste incineration units. If the material is not a solid waste, combustion units are required to meet the CAA section 112 emission standards for commercial, industrial, and institutional boilers or, if the combustion unit is a cement kiln, the CAA section 112 emissions standards for Portland cement kilns. Under CAA section 129, the term “solid waste incineration unit” is defined, in pertinent part, to mean “a distinct operating unit of any facility which combusts any solid waste material from commercial or industrial establishments . . .” 42 U.S.C. 7429(g)(1). The courts have determined that the CAA unambiguously requires any unit that combusts “any solid waste material at all”—regardless of whether the material is being burned for energy recovery—to be regulated as a solid waste incineration unit. See NRDC v. EPA (489 F.3d 1250 (D.C. Cir. 2007)).

    RCRA defines “solid waste” as “. . . any garbage, refuse, sludge from a waste treatment plant, water supply treatment plant, or air pollution control facility and other discarded material . . . resulting from industrial, commercial, mining, and agricultural operations, and from community activities . . .” (RCRA section 1004 (27) (emphasis added)). The key concept is that of “discard” and, in fact, this definition turns on the meaning of the phrase, “other discarded material,” since this term encompasses all other examples provided in the definition. In determining the meaning of discard, the courts have determined that the ordinary, plain English definition controls, i.e., discard means “disposed of,” “thrown away” or “abandoned.” See American Mining Congress v. EPA 824 F. 2d 1177 (D.C. Dir. 1987); see 76 FR 15460 for a detailed discussion on the RCRA definition of solid waste and CAA section 129.

    IV. Background A. History of the NHSM Rulemakings

    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 Federal Register on January 2, 2009 (74 FR 41). We then published an NHSM proposed rule on June 4, 2010 (75 FR 31844), which the EPA made final on March 21, 2011 (76 FR 15456).

    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 (e.g., coal, oil, natural gas) and “alternative” traditional fuels (e.g., clean cellulosic biomass) are not secondary materials and thus, are not solid wastes under the rule unless discarded.

    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 (i.e., via sham recycling). To meet the legitimacy criteria, the NHSM must be managed as a valuable commodity, have a meaningful heating value and be used as a fuel in a combustion unit that recovers energy, and contain contaminants or groups of contaminants at concentrations comparable to (or lower than) those in traditional fuels which the combustion unit is designed to burn.

    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.3 On February 7, 2013, the EPA published a final rule, which addressed specific targeted amendments and clarifications to the 40 CFR part 241 regulations (78 FR 9112). These revisions and clarifications were limited to certain issues on which the Agency had received new information, as well as targeted revisions that the Agency believed were appropriate in order to allow implementation of the rule as the EPA originally intended. The amendments modified 40 CFR 241.2 and 241.3, added 40 CFR 241.4, and included the following: 4

    3 See October 14, 2011, Letter from Administrator Lisa P. Jackson to Senator Olympia Snowe. A copy of this letter has been placed in the docket for this final rule (EPA-HQ-RCRA-2008-1873).

    4 See 78 FR 9112 (February 7, 2013) for a discussion of the rule and the Agency's basis for its decisions.

    Revised Definitions: The EPA revised three definitions discussed in the proposed rule: (1) “clean cellulosic biomass,” (2) “contaminants,” and (3) “established tire collection programs.” In addition, based on comments received on the proposed rule, the Agency revised the definition of “resinated wood.”

    Contaminant Legitimacy Criterion for NHSMs Used as Fuels: The EPA issued revised contaminant legitimacy criterion for NHSMs used as fuels to provide additional details on how contaminant-specific comparisons between NHSMs and traditional fuels may be made. The revisions include: (1) The ability to compare groups of contaminants where technically reasonable; (2) clarification that “designed to burn” means can burn or does burn, and not necessarily permitted to burn; (3) the ability to use traditional fuel data from national surveys and other sources beyond a facility's current fuel supplier; and (4) the ability to use ranges of traditional fuel contaminant levels when making contaminant comparisons, provided the variability of the NHSM contaminant levels is also considered.

    Categorical Non-Waste Determinations for Specific NHSMs Used as Fuels. The EPA codified determinations that certain NHSMs are non-wastes when used as fuels. If a material is categorically listed as a non-waste fuel, persons that generate or burn these NHSMs will not need to make individual determinations, as required under the existing rules, that these NHSMs meet the legitimacy criteria. Except where otherwise noted, combustors of these materials will not be required to provide further information demonstrating their non-waste status. Based on all available information, the EPA determined the following NHSMs are not solid wastes when burned as a fuel in combustion units and has categorically listed them in 40 CFR 241.4(a).5

    5 In the March 21, 2011 NHSM rule (76 FR 15456), EPA identified two NHSMs as not being solid wastes, although persons would still need to make individual determinations that these NHSMs meet the legitimacy criteria: (1) Scrap tires used in a combustion unit that are removed from vehicles and managed under the oversight of established tire collection programs and (2) resinated wood used in a combustion unit. However, in the February 2013 NHSM rule, the Agency amended the regulations and categorically listed these NHSMs as not being solid wastes.

    — Scrap tires that are not discarded and are managed under the oversight of established tire collection programs, including tires removed from vehicles and off-specification tires; — Resinated wood; — Coal refuse that has been recovered from legacy piles and processed in the same manner as currently-generated coal that would have been refuse if mined in the past; — Dewatered pulp and paper sludges that are not discarded and are generated and burned on-site by pulp and paper mills that burn a significant portion of such materials where such dewatered residuals are managed in a manner that preserves the meaningful heating value of the materials.

    Rulemaking Petition Process for Other Categorical Non-Waste Determinations: EPA made final a process in 40 CFR 241.4(b) that provides persons an opportunity to submit a rulemaking petition to the Administrator, seeking a determination for additional NHSMs to be categorically listed in 40 CFR 241.4(a) as non-waste fuels, if they can demonstrate that the NHSM meets the legitimacy criteria or, after balancing the legitimacy criteria with other relevant factors, EPA determines that the NHSM is not a solid waste when used as a fuel. Based on these non-waste categorical determinations, as discussed above, facilities burning NHSMs that meet the categorical listing description will not need to make individual determinations that the NHSM meets the legitimacy criteria or provide further information demonstrating their non-waste status on a site-by-site basis, provided they meet the conditions of the categorical listing. Please refer to section IV.C of this preamble for details on the petition process.

    B. Background to Final Rule

    As discussed in the February 2013 final rule,6 the Agency had received comments that additional NHSMs should be categorically listed as non-waste fuels for which the Agency had not requested information as a part of that proposal. We did not respond to such comments and issues since they were beyond the scope of that rulemaking and indicated that, because the Agency did not specifically solicit comments or propose that those NHSMs be categorically listed in 40 CFR 241.4(a), the Agency must go through notice and comment rulemaking before making a final decision. The February 2013 rule noted, however, that two NHSMs—paper recycling residuals (including old corrugated cardboard (OCC) rejects) and construction and demolition debris processed pursuant to best practices—would be good candidates for a future proposal based on information provided to the Agency and that EPA expected to propose those listings in a subsequent rulemaking.

    6 78 FR 9160.

    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).7 (refer to section V of this preamble or the regulatory text for a full description of this categorical listing).

    7 As noted above, the Agency also received a petition from the Treated Wood Council asking that non-hazardous treated wood be categorically listed—a broad category that would include creosote-treated railroad ties. Other treated wood addressed in the petition included 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. The Agency is in the process of reviewing that petition and supplementary information submitted subsequent to the petition. Accordingly, while cresosote treated wood railroad ties is included in the current rule, other treated wood materials identified in the Treated Wood Council's petition are not addressed in this action. If upon completion of the Agency's review, the information supports a categorical listing of one or more of these other treated wood materials, the Agency would propose those materials in a future rulemaking. See also discussion under Comments and Information Received on Other Types of Treated Wood in section V.A.6.c..

    C. How does the EPA make categorical non-waste determinations?

    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.89 These determinations follow the criteria set out in 40 CFR 241.4(b)(5) to assess additional categorical non-waste petitions and follow the statutory standards as interpreted by the EPA in the NHSM rule for deciding whether secondary materials are wastes. Those criteria include: (1) Whether each NHSM has not been discarded in the first instance (i.e., was not initially abandoned or thrown away) and is legitimately used as a fuel in a combustion unit or, if discarded, has been sufficiently processed into a material that is legitimately used as a fuel; and, (2) if the NHSM does not meet the legitimacy criteria described in 40 CFR 241.3(d)(1), whether the NHSM is integrally tied to the industrial production process, the NHSM is functionally the same as the comparable traditional fuel, or other relevant factors as appropriate.

    8 For a full discussion regarding the petition process for receiving a categorical non-waste determination, see 78 FR 9111, February 7, 2013 (page 9158-9159).

    9 Supplementary information received from by M.A. Energy Resources (February 2013) in support of the crosstie derived fuel was submitted as a categorical petition in accordance 40 CFR 241.4(b).

    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.

    V. Comments on the Proposed Rule and Rationale for Final Decisions

    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).

    A. Construction and Demolition Debris Processed According to Best Management Practices

    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.

    1. Detailed Description of C&D Wood

    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 construction activities, this debris results from cutting wood down to size during installation or from purchasing more wood than a project ultimately requires, while at demolition activities, this debris results from dismantling buildings and other structures or removing materials during renovation.10 Information previously compiled by the Agency indicates C&D activities generate an estimated 33 to 49 million tons of scrap wood each year, approximately half of which is of acceptable size, quality, and condition to be considered available for recovery. However, information on the amount of processed C&D wood that is burned for energy recovery is unavailable, although sources surveyed by EPA for the 2010 proposed CISWI rule and the National Emission Standards for Hazardous Air Pollutants for Area and Major Industrial, Commercial, and Institutional Boilers (Boilers) rule indicate that between 4.7 to 11.2 million tons per year of processed C&D wood may be burned for energy recovery.11

    10 Two revisions have been made to the definition of C&D wood. Please refer to section V.A.3. of this preamble for a discussion of the revisions to the definition of C&D wood for the final rule.

    11 Materials Characterization Paper: Construction and Demolition Materials. February 3, 2011. EPA-HQ-RCRA-2008-0329-1811.

    Also, because clean C&D wood is considered “clean cellulosic biomass” and is already excluded from being a solid waste,12 the Agency expected the proposed rule would address C&D wood generated predominantly from demolition activities. However, the proposal acknowledged clean C&D wood generated from construction activities that is mixed with contaminated C&D debris would be subject to the same practices and requirements described in the proposed rulemaking, because it is comingled with contaminated materials that would not constitute “clean cellulosic biomass.” The Agency finds, similarly, the practices and requirements adopted in this final rule, which are modified slightly from the proposal, also apply to the commingled materials generated from construction activities. No information was presented in this rulemaking to cause the Agency to find otherwise.

    12 Clean C&D wood is included in the definition of “clean cellulosic biomass” and thus, may be combusted as a traditional fuel if it does not contain contaminants at concentrations not normally associated with virgin wood. Conversely, C&D wood that is not “clean” is that which must be processed to remove contaminants such as lead-painted wood, treated wood containing contaminants, such as arsenic and chromium, metals and other non-wood materials. (See 76 FR 15485, March 21, 2011; 78 FR 9138-39, February 7, 2013; and 40 CFR 241.2).

    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 they specifically remove wood scraps from the co-mingled debris, picking out only desirable wood and leaving all other C&D debris behind for disposal or other recycling processes. Other operators use “negative sorting” techniques, meaning they achieve a similarly clean final product by removing or excluding contaminated or otherwise undesirable material from the C&D debris. Regardless of whether they use positive or negative sorting, processing facilities then grind the recovered wood to a specified size and deliver it to energy recovery facilities.

    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 (i.e., combustion facilities). The nature of the incoming C&D debris, the extent of material segregation prior to arrival at the processing facility, whether positive or negative sorting is employed, and the scale of the processing facility (e.g., the degree of sorting and number of screening devices) help determine which combination of practices will be most effective. Individual states also have different requirements related to the processing and combustion of C&D wood.13 Despite the variety of options, the Agency finds certain practices are essential to ensure processing of the C&D debris produces a legitimate product fuel. These practices, described in the proposal as best management practices, have been adopted in this final rule with minor changes and are discussed later in section V.A.3. of this preamble. In addition to excluding or removing a set list of C&D materials known to contain contaminants (e.g., certain types of treated wood), processors must take steps to eliminate less obvious contaminant sources (e.g., lead-based paint). Consequently, the standards proposed and finalized in this document, ensure that the contaminants in the fuel that is burned will not be unpredictable, even though the sources of the wood may vary.

    13 This final rulemaking does not change or replace existing state requirements regarding C&D wood. See section VIII. State Authority A. Relationship to State Programs of this preamble.

    2. C&D Wood Under Current NHSM Rules a. March 21, 2011 and February 2013 Final Rules

    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.14 First, “clean” C&D wood can be burned as a traditional fuel without any requirement for testing or recordkeeping—because it is a “clean cellulosic biomass” material indistinguishable in composition from virgin wood.15 Second, wood recovered from C&D debris (i.e., contaminated wood) can be sufficiently processed to meet the legitimacy criteria and, thus, would be a non-waste fuel, although combustion facilities burning the material would need to keep records documenting the material's non-waste status. Records would need to document not only how the processing operations meet the definition of processing in 40 CFR 241.2, but also how the product fuel meets the NHSM legitimacy criteria in 40 CFR 241.3(d)(1).16 17

    14 76 FR 15485, March 21, 2011 and 78 FR 9138, February 7, 2013.

    15 In the February 7, 2013 final rule (78 FR 9139), the Agency emphasized that, “determinations that the cellulosic biomass used as a fuel or ingredient is clean, do not presuppose any testing of contaminant levels. Persons can use expert or process knowledge of the material to justify decisions regarding presence of contaminants.”

    16 Recordkeeping requirements for area source boilers are found at 40 CFR 63.11225(c)(2)(ii), while recordkeeping requirements for major source boilers are found at 40 CFR 63.7555(d)(2).

    17 While the combustor would be responsible for maintaining the records that such NHSM met the legitimacy criteria, the combustor could request that the person that generated the C&D wood provide documentation that the processing operations meet the definition of processing, as well as the legitimacy criteria, especially the contaminant legitimacy criterion.

    b. December 2011 Proposed Rule

    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 (i.e., recovered from demolition activities) should be categorically listed as a non-waste fuel under 40 CFR 241.4(a), or otherwise a non-waste.18 The commenters' rationale for listing processed C&D wood as a non-waste is as follows.

    18 Comments submitted on the December 23, 2011 proposed rule are included in docket: EPA-HQ-RCRA-2008-0329. Specifically, see the document ID#'s ending in -1902, -1910, -1950, -1930, -1928, -1946, -1957, -1927, -1893, and -1905.

    • 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 C&D wood should be regulated as a solid waste because they view it as having been discarded similar to scrap tires. Another commenter requested the EPA require testing for contamination based on what they described as highly unpredictable contaminant levels. The commenter referenced specific combustion facilities that accepted C&D wood, including lead-painted wood and CCA-treated wood, as well as plastics and foreign debris to support a requirement for testing. In addition, the same commenter argued that C&D wood should only be compared to clean untreated wood when conducting a contaminant comparison, not necessarily what the unit is designed to burn.19 The Agency's decision on this final rule considers the issues raised in these comments on the December 2011 proposed rule. Responses to the issues raised in these comments are included in section V.A.6. of this preamble.

    19 Comments submitted on the December 23, 2011 proposed rule (76 FR 80452) are included in docket: EPA-HQ-RCRA-2008-0329. Specifically, see the document ID numbers ending in -1959 and -1974.

    3. Scope of the Proposed Rule and Final Categorical Non-Waste Listing for C&D Wood

    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.20 Such practices include sorting by trained operators that excludes or removes non-wood materials (e.g., polyvinyl chloride and other plastics, drywall, concrete, aggregates, dirt, and asbestos), and wood treated with creosote,21 pentachlorophenol, chromated copper arsenate, or other copper, chromium, or arsenical preservatives. In addition, C&D processing facilities that use positive sorting (where operators pick out desirable wood from co-mingled debris) must either exclude all painted wood from the final product fuel, use X-ray Fluorescence to ensure that painted wood included in the final product fuel does not contain lead-based paint, or require documentation that a building has been tested for and does not include lead-based paint before accepting demolition debris from that building.

    20 If the processed C&D wood does not meet the categorical listing, the wood may still be considered a non-waste fuel (on a case-by-case basis), although any combustor that burns such processed C&D wood would need to keep records documenting the materials non-waste status pursuant to 40 CFR 63.11225(c)(2)(ii) and 40 CFR 63.7555(d)(2).

    21 Although industry trade groups did not list creosote treated wood as wood that is excluded or removed, they provided information indicating that C&D debris can include creosote treated wood. Based upon the contaminants present in creosote treated wood and the types of boilers that burn C&D wood (i.e., those that are designed to burn clean wood and biomass), operators must exclude or remove creosote treated wood. With respect to creosote and as discussed later in section V.C of this preamble, the Agency evaluated data provided for creosote-treated railway ties and determined that boiler design was an integral factor in satisfying the contaminant legitimacy criterion.

    C&D processing facilities that use negative sorting (where operators remove contaminated or otherwise undesirable materials from co-mingled debris) must remove fines, i.e., small-sized particles that may contain relatively high concentrations of lead and other contaminants, and either remove painted wood, use X-ray Fluorescence to detect and remove lead-painted wood, or require documentation that a building has been tested for and does not include lead-based paint before accepting demolition debris from that building.

    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.

    Lead Elimination Requirements. One of the changes between the proposed rule and final rule concerns the lead elimination requirements for positive sorting processors. The lead exclusion language for positive sorting processors proposed at 40 CFR 241.4(a)(5)(i) did not specifically provide that facilities receiving pre-sorted wood from positive sorting entities who may need to remove small amounts of unwanted material prior to chipping and grinding the wood are also considered positive sorting facilities. Because these facilities remove some materials, they could be considered negative sorters.

    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.22 These small generators (e.g., contractors, community collections, citizen drop-off locations, and transfer stations) segregate and collect clean C&D wood using positive sorting and provide the recovered C&D wood to “chip and grind” processors. The chip and grind processors then conduct additional sorting, using negative sorting techniques, to remove small amounts of unwanted materials from the shipment prior to processing. These processors should not be considered negative sorters.

    22 See comments and data submitted by Covanta (EPA -HQ-RCRA-2013-0110-0084), comments from American Reclamation Inc. (EPA-HQ-RCRA-2013-0110-0073), and comments from Genesee Power Station (GPS) (EPA-HQ-RCRA-2013-0110-0091).

    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—or that receive and process positive sorted C&D wood must either . . .”

    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 wood received must be removed (or excluded in the case of positive sorting facilities). The purpose of this change is to ensure all painted wood, regardless of sorting practices, is eliminated from the final product if the processor chooses this lead elimination strategy. While it is expected that processors will make every effort to remove or exclude all painted wood under this option, de minimis amounts could be present and still render the resultant material a product fuel. The final regulatory language adds new text to 40 CFR 241.4(a)(5)(ii)(A), and now states “[r]emove all painted wood.”

    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 de minimis amounts, we have added the following language as a parenthetical to both 40 CFR 241.4(a)(5)(i)(A) and (ii)(A): “(to the extent that only de minimis quantities inherent to processing limitations may remain)”.

    Definition of C&D wood. Two revisions to the definition of C&D wood (40 CFR 241.2) have been made. One revision is to include disaster debris and the second revision is to broaden what the Agency considers to be wood recovered from construction activities.

    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 (e.g., lead-based painted wood, CCA treated wood, asbestos containing materials, utility poles, etc.) and sent for processing without any prior sorting. Also noted in the proposal, and of particular concern to the Agency, was that management of disaster debris is more expedited and less controlled and thus, prone to include contaminants that might otherwise be sorted out prior to processing.23 Therefore, the Agency solicited comment on whether disaster debris should be included in the definition of C&D wood despite some concerns related to processing large volumes of material expeditiously.

    23 Management of disaster debris can involve significantly greater volumes. For example, prior to the 1994 Northridge earthquake in Los Angeles, one local company processed 150 tons of C&D debris per day. After the earthquake, the city picked up as much as 10,000 tons of C&D debris per day.

    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.24 Given the best management practices and information indicating the typical handling of excess material, the Agency has determined it is appropriate to include disaster debris in the definition of C&D wood. Thus, clean wood from natural disaster debris mixed with other materials and delivered to a processing facility has been added to the definition of C&D wood. However, the natural disaster debris must be processed in the same manner as C&D wood recovered from C&D activities to qualify for this categorical non-waste listing. The last sentence of the definition for C&D wood at 40 CFR 241.2 has been revised to add text for natural disasters and now reads: “C&D wood from demolition activities results from dismantling buildings and other structures, removing materials during renovation, or from natural disasters.”

    24 See comments from American Forest & Paper Association (EPA-HQ-RCRA-2013-0110-0076) and Waste Management (EPA-HQ-RCRA-2013-0110-0094.

    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 cutting wood down to size during installation or from purchasing more wood than a project ultimately requires.” A commenter suggested listing additional types of installation activities associated with construction such as incorrectly cut wood, wood forms, support braces, stakes, etc. Rather than trying to provide an exhaustive list, which may not include every possible type of installation activity, the Agency has decided to revise the language to capture any type of installation activity that can generate construction wood debris. The second sentence of the definition now reads “C&D wood from construction activities results from wood generated during any installation activity or from purchasing more wood than a project ultimately requires.” The change acknowledges there are several ways installation activities can generate wood without limiting those activities.

    Training and certification. Two regulatory additions have been made based on concepts that had been discussed in the proposed rule preamble. One addition is a requirement for C&D processors to train their operators. The approach taken in the proposal was to not include a specific training requirement for processors, but to rely on a written certification as a means for processors to show they had used “trained” operators (79 FR 21026). However, the Agency finds 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 waste. Although the written certification statement, as proposed (and finalized in this rule), must state the processed C&D wood has been sorted by “trained” operators in accordance with best management practices, it did not require any evidence that training has taken place, nor did it hold the processor accountable to their customers. Thus, a mechanism is necessary to document when the training has been conducted so that processors are accountable when certifying they have used trained operators. This mechanism is implemented via new regulatory language at 40 CFR 241.4(a)(5)(iii) which states “[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. For further discussion, see section V.A.5 of this preamble.

    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.

    4. Rationale for Final Rule

    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.

    a. Discard

    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.

    i. Processing of C&D Wood

    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.25 In accordance with 40 CFR 241.2, processing must include 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 (e.g., sizing or drying of the material, in combination with other operations); chemically improve the as-fired energy content; or improve the ingredient characteristics. Minimal operations that result only in modifying the size of the material by shredding do not constitute processing for the purposes of the definition.

    25 This rulemaking does not change the waste status of C&D wood prior to processing, up to which point the material would likely be a solid waste subject to appropriate federal, state, and local requirements unless it meets the definition of “clean cellulosic biomass.”

    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,26 will result in significant contaminant removal. In addition, the removal of concrete, aggregates, dirt, and other non-combustible material will significantly increase the material's energy value. Finally, grinding all remaining wood to a specified size will allow combustors to transport, store, and use processed C&D wood in the same manner as virgin wood and biomass materials.

    26 CAA regulations provide additional safeguards to ensure asbestos is removed from buildings prior to demolition. Part 61, subpart M (40 CFR 61.145) requires that owners or operators of a demolition or renovation activity to inspect the affected building for the presence of asbestos prior to demolition or renovation and notify the Administrator. EPA notes, however, that the 40 CFR 61.141 definition of “facility” explicitly excludes “residential buildings having four or fewer dwelling units” thus, small residential buildings that are demolished or renovated are not covered by the Federal asbestos NESHAP regardless of whether the demolition or renovation is performed by agents of the owner of the property or whether the demolition or renovation is performed by agents of the municipality. See also the “Asbestos NESHAP Clarification of Intent” (60 FR 38725; July 28, 1995).

    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 (i.e., combustion facilities). The nature of the incoming C&D debris, the extent of material segregation prior to arrival at the processing facility, whether positive or negative sorting is employed, and the scale of the processing facility (e.g., the degree of sorting and number of screening devices) help determine which combination of practices will be most effective. The Agency has determined that the best management practices, when performed by trained operators, addresses the variability within the industry such that C&D processing facilities will produce a non-waste product with contaminants that are no greater than clean wood and biomass, regardless of the characteristics that can influence the level of contaminants in the C&D wood. Thus, the Agency finds such processing meets the definition of processing in 40 CFR 241.2.

    ii. Certification

    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 final processor of C&D wood. The written certification must include the statement: The processed C&D wood has been sorted by trained operators in accordance with best management practices. Combustors have the ultimate responsibility to determine the C&D wood has been sufficiently processed.

    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.

    b. Legitimacy Criteria

    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).

    i. Managed as a Valuable Commodity

    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.27 Because storage does not exceed reasonable time frames, and management is similar to that of virgin wood and biomass, the Agency has determined that processed C&D wood meets this legitimacy criterion.

    27 See December 7, 2012 letter from Susan Bodine to Suzanne Rudzinski, page 3. EPA-HQ-RCRA-2008-0329-2009.

    ii. Meaningful Heating Value and Used as a Fuel To Recover Energy

    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,28 which is greater than 5,000 Btu/lb, which the Agency considers to have a meaningful heating value (see 76 FR 15541, March 21, 2011). This also compares favorably to information compiled by the Agency in 2011, in which 95 samples of unadulterated timber burned by major source boilers29 across the country exhibited an average as-fired energy content of 5,150 Btu/lb.30 According to C&D trade organizations, energy recovery facilities purchase processed C&D wood and burn the material as fuel to generate electricity. Thus, the Agency has determined that processed C&D wood meets this legitimacy criterion.

    28 Appendix A of April 25, 2013, submittal from Susan Bodine on behalf of BPA and CMRA, available in the Docket at EPA-HQ-RCRA-2013-0110.

    29 Major sources are

    30 USEPA, Office of Air Quality Planning and Standards, Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM & Fuel Analysis Data Reported Under ICR No. 2286.01 and ICR No. 2286.03 (Version 6). EPA Docket/Document Number EPA-HQ-OAR-2002-0058-3255. February 2011.

    iii. Contaminants Comparable to or Lower Than Traditional Fuels

    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.31

    31 In response to the proposal, EPA did receive data showing a contaminant comparison to coke and coal. However, the data was specific to cement kilns and cannot be considered to be representative for all unit types that combust processed C&D wood (i.e., some boilers cannot burn coal depending upon feed systems or boiler design type) and therefore, was not analyzed for this final rule. A case-by-case comparison, however, can be made using traditional fuels such as coke and coal if the combustion unit is designed to burn these materials and if the concentrations of contaminants are found to be comparable to or less than those present in C&D wood, then the contaminant criterion would be met.

    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.

    Table 1—Comparison of Contaminants in Clean Wood/Biomass and Processed C&D Wood 323334 Contaminant Clean Wood/Biomass Range Processed C&D Wood # samples Average 90% UPL Maximum Contaminants Most Likely To Be Present in C&D Debris Arsenic ND—298 n = 221 35.9 91.8 261 Chromium ND—340 n = 212 45.0 116 283 Lead ND—340 n = 224 53.9 136 482 Mercury ND—1.1 n = 180 0.1 0.16 0.7 Chlorine ND—5400 n = 173 809 1,567 3,521 Fluorine ND—300 n = 86 45.9 139 313 Sulfur ND—8700 n = 183 1,300 2,200 7,300 Formaldehyde 1.6—27 n = 45 47.6 104.2 176.8 Pentachlorophenol ND n = 21 19.7 N/A 126 Contaminants Less Likely To Be Present in C&D Debris Antimony ND—26 n = 50 2.6 7.1 16.6 Beryllium ND—10 n = 50 0.1 0.23 0.3 Cadmium ND—17 n = 107 0.3 0.53 1.3 Cobalt ND—213 n = 50 1.1 2.1 3.5 Manganese ND—15800 n = 50 78.8 115 180 Nickel ND—540 n = 50 4.0 8.6 27.4 Selenium ND—9 n = 43 0.4 1.0 1.3 Nitrogen 200—39500 n = 75 3,900 8,000 12,600

    32 Sources: Clean Wood/Biomass ranges taken from a combination of EPA data and literature sources, as presented in EPA document Contaminant Concentrations in Traditional Fuels: Tables for Comparison, November 29, 2011, available at www.epa.gov/epawaste/nonhaz/define/index.htm. Processed C&D Wood data from April 26, 2013, submittal by Susan Bodine on behalf of BPA and CMRA, available in the Docket at EPA-HQ-RCRA-2013-0110.

    33 All units expressed in parts per million (ppm) on a dry weight basis.

    34 Upper Prediction Limit (UPL) calculations were made by commenters using EPA's ProUCL software, using either a lognormal distribution or nonparametric statistics, as appropriate.

    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 (i.e., 313 ppm is comparable to 300 ppm).35 36 Thus, the final rule does not include controls specific to fluorine.

    35 76 FR 15523-24, March 21, 2011.

    36 In addition to determining that the one sample of fluorine is within a small acceptable range, one can consider that the Upper Prediction Limit (UPL) for fluorine in processed C&D wood, when calculated at a 90 percent confidence level based on all 45 samples (139 ppm), is well within the range of clean wood and biomass materials. The UPL taken at a 90 percent confidence level yields a number (i.e., 139 ppm), and in the context of analyzing contaminant samples, persons can be confident that the next sample taken will be at or below that number 90 percent of the time.

    • 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 debris into a product fuel in all cases that would warrant processed C&D wood being categorically listed as a non-waste fuel. Thus, the Agency had proposed conditions related to lead elimination as part of the categorical non-waste listing for processed C&D wood. The proposed conditions were:

    —Facilities using positive sorting must either: (1) Exclude painted wood via the sorting process by selecting only unpainted wood from incoming C&D debris for further processing, (2) use XRF to ensure that painted wood included in the final product fuel does not contain lead-based paint, or (3) require documentation that a building has been tested for and does not include lead-based paint before accepting demolition debris from that building. —Facilities using negative sorting must remove fine particles, which may include asbestos fibers and other contaminants in addition to lead, and they must also either: (1) Remove painted wood via the sorting process, (2) use XRF to detect and remove lead-painted wood, or (3) require documentation that a building has been tested for and does not include lead-based paint before accepting demolition debris from that building.

    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 de minimis quantities inherent to processing limitations may remain” has been added to both 40 CFR 241.4(a)(5)(i)(A) and (ii)(A) to reflect the Agency's position on de minimis amounts.

    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.37 Therefore, under the proposed regulatory conditions, processing facilities must exclude or remove these known sources of pentachlorophenol from their final product fuel to qualify for the categorical non-waste listing.

    37 Based on discussions with plant staff during an EPA tour of Industrial Disposal Services, Inc. Broad Run Recycling facility in Manassas, Virginia on May 23, 2013. The facility processes discarded C&D wood into a product fuel.

    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.38 Because sources of pentachlorophenol can be readily identified by color and by shape of the treated wood, no additional conditions other than those specified by the best management practices are necessary. Thus, to ensure that pentachlorophenol levels in processed C&D wood are comparable to or lower than clean wood and biomass, the Agency is requiring that pentachlorophenol treated wood be excluded or removed from incoming C&D debris. See 40 CFR 241.4(a)(5). The Agency sees no reason to change the determination expressed in the proposed rule and adopts it for the final rule.

    38 See comments from AF&PA (0076.1), DTE Energy Services (0083.1), and NTH Consultants LTD for CMS Enterprises (0100) in docket ID: EPA-HQ-RCRA-2013-0110.

    • 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.39 Second and more importantly, for many combustors, processed C&D wood scraps that include resinated wood components actually have added value and are either selected for (in the case of positive sorting) or specifically not removed (in the case of negative sorting) because the wood has been kiln-dried prior to use in construction. Kiln-dried wood has a greater heating value than virgin wood, almost double in some cases. Kiln-dried wood also has more consistent moisture content; an equally important benefit to combustors because a consistent fuel improves combustion efficiency and leads to reduced emissions of particulate matter, carbon monoxide, and other organic hazardous air pollutants.

    39 On May 29, 2013, EPA proposed two rules to protect the public from the risks associated with exposure to formaldehyde. 78 FR 34796, 78 FR 34820. The proposals would implement the Formaldehyde Standards for Composite Wood Products Act (Title VI of the Toxic Substances Control Act): One will implement the Act's emission standards and the other will ensure products meet the TSCA formaldehyde emission standards. See http://www.epa.gov/oppt/chemtest/formaldehyde/.

    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.

    5. Summary of Comments Requested

    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.

    Processing Techniques for lead and pentachlorophenol. The Agency requested comment on the efficacy of specific processing techniques related to lead, as well as the feasibility of reducing pentachlorophenol concentrations in processed C&D wood by excluding or removing utility poles and other industrial wood products known to be treated with the chemical. See 79 FR 21015, April 14, 2014. Please refer to section V.A.4.b.iii of this preamble for the Agency's final determination and supporting rationale.

    Formaldehyde levels. The Agency sought comment on the decision to balance elevated formaldehyde levels with the greater heating value and more consistent moisture content that resinated wood components lend to processed C&D wood, rather than specifically requiring that resinated wood be excluded or removed from C&D debris as part of the best management practices. See 79 FR 21015-16. Please refer to section V.A.4.b.iii of this preamble for the Agency's final determination and supporting rationale.

    CCA-treated wood. As proposed at 79 FR 21016, CCA-treated wood was to be excluded or removed from C&D debris. Although the data submitted to the Agency indicated that arsenic and chromium concentrations in processed C&D wood are comparable to levels found in traditional fuels, there was concern that because a majority of CCA-treated wood is still in use, an increase in the amount of CCA-treated wood in C&D debris can be expected in the future. Currently, CCA-treated wood can represent up to 30 percent of the C&D wood waste stream.40 The concern was further compounded by the reality that visual identification of CCA-treated wood is at times very difficult, especially when the wood is weathered, dirty, painted, or if the wood is characterized by low retention levels.41

    40 Fattah, Hassan Abdel, et al. “Online Sorting of Recovered Wood Waste Using Automated X-Ray Technology” Final Report; November 30, 2009. See p. 2. Available in EPA-HQ-RCRA-2013-0110.

    41 Blassino, Monika, et al. “Methods to control Fuel Quality at Wood Burning Facilities.” Available in EPA-HQ-RCRA-2013-0110-0033.

    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 (e.g., PAN Indicator Stain 42 ) and X-ray Florescence (XRF) technology are the most promising technologies, with chemical stains being suitable for sorting small quantities of wood and XRF technology being better suited for sorting large quantities of wood.

    42 PAN stands for the chemical name of 1-(2-pyridylazo)-2-naphthol, an orange-red solid with a molecular formula C15H11N3O. It is used to determine the presence of almost all metals excluding alkali metals. The stain is not specific to arsenic within CCA. It reacts with the copper, so that wood treated with any copper-based preservative will also test positive using this stain.

    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 stains are limited in application when processing large amounts of C&D debris. The evidence demonstrates that processors who train their employees to visually recognize treated wood are successful in excluding or removing CCA-treated wood.43 Therefore, by requiring processors to train their operators as part of this categorical non-waste listing, it will further ensure that levels of arsenic and chromium in processed C&D wood remain comparable to or lower than levels in clean wood and biomass as more CCA-treated wood is introduced into C&D debris.

    43 Blassino, Monika, et al. “Methods to Control Fuel Quality at Wood Burning Facilities.” EPA-HQ-RCRA-2013-0110-0033.

    Disaster Debris. The definition for C&D wood as proposed did not include disaster debris. The Agency had defined “clean cellulosic biomass” to include clean wood found in disaster debris.44 However, disaster debris wood that is mixed with contaminated materials (e.g., lead-based painted wood, asbestos containing materials, etc.) had not been specifically addressed. The Agency noted in the proposal that management of disaster debris is more expedited and less controlled and thus, prone to include contaminants that might otherwise be sorted out prior to processing.45 In light of these concerns, the Agency requested comment on the appropriateness of including wood that is recovered from disaster debris, but that is mixed with other contaminated materials prior to arrival at the processing facility, as processed C&D wood. Thus, the Agency requested that commenters provide any data or information to demonstrate that mixed disaster debris wood, once processed, produces wood that contains contaminants comparable to or lower than biomass and virgin wood. Further, the EPA also requested comment on whether other conditions imposed by contingency plans, for example, can facilitate the removal of contaminated material found in disaster debris.

    44 76 FR 15478 (March 21, 2011); codified at 40 CFR 241.2.

    45 Management of disaster debris can involve significantly greater volumes. For example, prior to the 1994 Northridge earthquake in Los Angeles, one local company processed 150 tons of C&D debris per day. After the earthquake, the city picked up as much as 10,000 tons of C&D debris per day.

    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.

    Trained operators. As presented in the proposal at 79 FR 21016, best management practices require sorting by “trained operators” to remove or exclude all non-wood debris, certain treated wood, and lead-based painted wood from the final product fuel. The Agency noted that operators who are trained to sort C&D debris, especially to recognize treated wood, play an important role in reducing contaminant levels in the final product fuel. Therefore, comment was requested on whether the Agency should require C&D processors to have formal training programs in place as part of the best management practices, as well as whether processors should be required to keep records as a condition of the categorical listing to demonstrate that such operators have been formally trained.

    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 (i.e., the degree of sorting and screening devices) are variable within the industry. Thus, the Agency sought comment on whether to require processors to have formal training programs, and if so, requirements that would be flexible enough to address the variability of the incoming C&D debris, but also provide additional assurance that C&D processing facilities would produce a non-waste product fuel with contaminants that are comparable to or lower than clean wood/biomass.

    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.

    Written Certification. As proposed at 79 FR 21016, the combustor would need to obtain a written certification from the C&D processor that the C&D wood has been processed by trained operators in accordance with best management practices. The Agency proposed that the written certification could take the form of a contract, purchase agreement, or other document that requires the supplier to process the C&D wood according to combustor specifications and best management practices. It was the Agency's understanding that purchase agreements and contracts are common between a processor/supplier and combustor. Thus, comment was requested on whether such agreements and contracts are sufficient documentation (i.e., can serve as the written certification) or if a written certification statement developed specifically to address the requirements in the proposal would be clearer and more effective. The Agency noted that the existing record keeping requirements for combustors that combust NHSMs as fuels listed under 40 CFR 241.4,46 would be appropriate for maintaining the certification. The purchase agreement, contract, or other document, would be considered a “record” which satisfies the record keeping requirements of 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.47

    46 40 CFR 241.4 lists the categorical or “Non-waste determinations for specific non-hazardous secondary materials when used as a fuel.”

    47 These sections state that “for operating units that combust non-hazardous secondary materials as fuel per 40 CFR 241.4, you must keep records documenting that the material is listed as a non-waste under 40 CFR 241.4(a).”

    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).

    6. Response to Comments a. Definition of Construction and Demolition (C&D) Wood

    Comment: Commenters supported the inclusion of disaster debris in the definition of C&D wood, generally arguing that the definition already includes disaster debris because it does not distinguish between the demolition and dismantling of buildings by nature or man. Man-made demolition debris will not necessarily be distinguishable from debris created by nature. Managing wood from natural disasters requires the same processes used for [man-made] C&D debris. Although a natural disaster may increase the quantity of C&D wood available for processing, processors will follow the same practices in terms of material acceptance and processing. Where incoming material exceeds processing capacity and cannot be stored, the material will typically be landfilled. In addition, purchasers of processed C&D wood will continue to require material that meets or exceeds their specifications, so processors must continue to exert tight controls to avoid risking rejected materials. The [proposed] regulatory requirements for training and processing would still prevail. Accordingly, the EPA should amend the last sentence of the definition that addresses C&D wood from demolition activities to include “natural disasters.”

    Response: We agree that the definition of C&D wood should include the term “natural disaster” to represent activities resulting from natural disaster events. Accordingly, the Agency has revised the definition from the proposal so that the last sentence now reads “C&D wood from demolition activities results from dismantling buildings and other structures, removing materials during renovation, or from natural disasters.”

    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 (i.e., via positive sorting) from the disaster debris site and sent to a processor for chipping and grinding, it is considered clean cellulosic biomass, which is a traditional fuel. However, the Agency had not addressed clean wood from disaster debris that is mixed with contaminated materials which could include other types of treated wood, drywall, plastics, concrete and so forth, that is delivered to a processing facility. When clean wood from disaster debris is not picked/sorted prior to arrival at a processing facility, it is no different than C&D debris and thus, must be processed in the same manner to qualify for this categorical non-waste listing.

    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 natural disaster debris must be processed in the same manner as C&D wood recovered from C&D activities to qualify for this categorical non-waste listing.

    Comment: The definition of C&D wood should be expanded with respect to the sources of wood generated from construction activities. As proposed, the second sentence of the definition states “C&D wood from construction activities results from cutting wood down to size during installation or from purchasing more wood than a project ultimately requires.” This sentence may be too prescriptive, since wood can also be generated from incorrectly cut wood, wood used for concrete forms, wood used for support braces, and other uses which render the wood unsuitable for installation.

    Response: The definition of C&D wood as applied to construction activities was not intended to be limited to a specific installation activity (i.e., cutting wood down to size). The Agency, however, understands that it may be read to be prescriptive. To address any ambiguity, the Agency has revised the second sentence for construction and demolition (C&D) wood at 40 CFR 241.2 with the following, “C&D wood from construction activities results from wood generated during any installation activities or from purchasing more wood than a project ultimately requires.” Thus the definition is not limited to “cutting wood down to size” but allows any waste wood generated at any time during installation to be considered construction debris. Although the revision does not specifically list the specific installation activities as suggested, it now acknowledges that there are a number of different ways that construction activities can generate wood without limiting applicable activities by specifically listing them in the definition.

    b. Contaminant Comparison Criterion

    Comment: Changes should be made to the method for comparing contaminant levels in processed C&D wood. Rather than comparing the constituents of concern to virgin wood or biomass, the Agency should consider establishing a standard based on analytical surveys of well-sorted C&D debris and use the test results as the standard. Also, specific contaminant levels need to be developed by the Agency to clearly define what a legitimate fuel product is that can be burned as a non-waste. Without a clearly defined set of contaminant levels, the rule will be very difficult to enforce.

    Response: We disagree that any modifications to the contaminant comparison legitimacy criterion should be made, particularly with respect to establishing what the Agency considers a “bright line” or even a numerical approach to setting levels for C&D wood. The issue is not that analytical surveys of well-sorted C&D debris establish a standard. Rather, the levels in the processed C&D wood must compare favorably to the traditional fuels that it replaces. The rationale for comparison of a NHSM's contaminant concentrations to the traditional fuels which the combustion unit is designed to burn is explained in several related rulemakings.48

    48 74 FR 54 (January 2, 2009), 75 FR 31883 (June 4, 2010), and 76 FR 15526 (March 21, 2011).

    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.49 Thus, an NHSM must contain contaminants at levels that are comparable to or lower than the range provided for the traditional fuel on a case-by case basis to qualify as a product fuel.

    49 76 FR 15525-26.

    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 (i.e., case-by-case) determinations that it meets the legitimacy criteria (see 79 FR 21009). Specifically for C&D wood, the Agency has evaluated all data and information and has determined that C&D wood processed according to best management practices is transformed into a legitimate product fuel and is appropriately listed as a categorical non-waste. Thus, a case-by-case comparison of contaminant levels in processed C&D wood to clean wood/biomass is not required for C&D wood processed according to best management practices. However, if the processing of C&D wood is found to be in non-compliance with conditions of this listing, the combustor may face enforcement action.

    c. Construction and Demolition (C&D) Wood Processed From C&D Debris According to Best Management Practices

    Comment: C&D wood should be regulated as a solid waste because it is discarded similar to scrap tires.

    Response: The Agency agrees that a discarded NHSM is a solid waste first. However, the commenters make an incorrect comparison between C&D wood and scrap tires. In the March 21, 2011 final rule, the Agency stated that “. . . a system where scrap tires are removed from vehicles and are collected and managed under the oversight of established tire collection programs are not discarded in the first instance . . . [t]hese programs ensure that the tires are not discarded en route to the combustor for use as a fuel and are handled as a valuable commodity . . .” 50 In this case, the commenters did not acknowledge the Agency's previous determination that not all scrap tires are discarded. Moreover, the Agency later finalized a categorical non-waste listing for scrap tires that are not discarded. See the final rule in the Federal Register at 78 FR 9154, February 7, 2013, and 40 CFR 241.4.

    50 See 76 FR 15491-92.

    Contrary to scrap tires, mixed C&D debris (i.e., it is not composed of only clean cellulosic biomass) is discarded in all instances and must be processed sufficiently to transform the resulting C&D wood into a legitimate non-waste fuel. This is unlike scrap tires, where only the scrap tires that have been discarded must be processed to become a non-waste fuel.

    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 categorical non-waste when specific conditions are met which are: conducting processing according to best management practices, conducting training, and providing a written certification. These conditions are designed to ensure that the resulting C&D wood is a non-waste product fuel.

    Comment: The EPA's March 21, 2011 document “Identification of non-hazardous secondary materials that are solid waste” states that when C&D is sorted, painted wood is removed. This is misleading and is not the case. Painted and contaminated wood is routinely burned as evidenced by an interview at a processing facility where the plant manager stated that the “positive pick” process did not remove painted wood from the line and by a photograph of the same facility's processed C&D wood containing painted wood. In addition, another processing facility whose product fuel is reported to consist of forest industry waste, shredded construction wood waste, and demolition debris also contains significant amounts of paper, plastic, and foreign debris.

    Response: The commenter misconstrues the Agency's discussion of processed C&D wood in the final rule at 76 FR 15485, March 21, 2011. When describing how contaminated C&D wood can become a non-waste product fuel, the Agency stated that “C&D-derived wood is typically sorted to remove contaminants (e.g., lead-painted wood, treated wood, non-wood materials), and size reduced prior to burning, producing material that likely meets the processing and legitimacy criteria for contaminants.” Nothing in this statement specifically says that painted wood is removed through the sorting process. Furthermore, the Agency notes that not all painted wood is lead-based and thus, does not present the same contaminant concerns.

    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.

    Comment: The EPA must require testing for contamination. C&D as a waste fuel is extremely variable. “Slugs” of contaminated wood move through sorting facilities at various times.

    Response: The Agency agrees that C&D debris is extremely variable as a waste. 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 (i.e., the degree of sorting and screening devices) further contributes to variability within the industry. To address this variability, the Agency has finalized best management practices (see 40 CFR 241.4(a)(5)) for this categorical non-waste listing that require specific materials to be excluded or removed during processing. Also, as part of the best management practice requirements, C&D processors must certify that their processed C&D wood has been sorted by trained operators.51

    51 For a complete discussion of the certification and training requirements, see section V.A.3. of this preamble. These requirements are codified at 40 CFR 241.4(a)(5)(iii) and (iv).

    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).

    Comment: Copper should be deleted from the best management practice list of materials that are to be excluded or removed from the final product fuel. While the list includes materials that may not qualify as non-hazardous and materials that are addressed separately in the proposal, it overreaches by including copper, which is neither hazardous nor a listed Hazardous Air Pollutant (HAP). The proposed rule's preamble provides no basis for requiring exclusion or removal of wood that contains copper, and it is not necessary to include this restriction in order to avoid concerns about CCA or other arsenic or chromium-based preservatives, since they are covered by provisions in the proposed rule.

    Response: The Agency disagrees that copper should be deleted from the list of materials to be excluded or removed. The Agency had previously found, based on information in the June 2010 proposed rule and the March 21, 2011 final rule that wood treated with copper napthenate is considered a solid waste because of concerns of elevated contaminants. At the time of these rules, the Agency indicated that it did not have sufficient information on contaminant levels in wood treated with copper naphthenate.52 53 As a result, we have determined that copper should remain on the list.

    52 75 FR 31863 and 76 FR 15484.

    53 Since publication of these rules and the April 2014 proposal (79 FR 21005), the Agency has received a petition for a categorical non-waste listing for other treated wood types (included in the docket for this rule), one of which is wood treated with copper naphthenate. The petition included contaminant data for wood treated with copper naphthenate and is under evaluation.

    Comment: In the third sentence of the proposed regulatory language for the best management practices, specific materials are required to be excluded or removed. This is much too restrictive because it can be interpreted as meaning all listed materials must be completely removed from the C&D debris. The requirement as proposed would render the requirement unworkable and impossible to meet. It would be more appropriate to require that the BMPs “substantially exclude or substantially remove” unwanted materials in order to recognize that some small amount of unwanted materials, although insignificant, may pass through the C&D stream even when using BMPs. Similarly, the proposed regulatory paragraph at 40 CFR 241.4(a)(5)(ii) contains the terms “remove” and “must remove.” Again, these terms are believed to be overly prescriptive, and should be modified to recognize that small, insignificant amounts of undesirable materials may be present in the final fuel product.

    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.

    Response: The Agency did not intend that the terms “excludes” and “removes” to mean that 100 percent of the listed materials be excluded or removed, or that the listed materials must be completely removed from the C&D debris during processing. While it is essential to exclude or remove the listed materials, the Agency also recognizes that a material would still be a non-waste even if there are some negligible or de minimis amounts of contaminants in the final combusted material. This is supported by the rulemaking record, specifically the discussion in the March 21, 2011 final rule where commenters argued that there should be a de minimis exemption for processed C&D wood to address small or de minimis amounts of material remaining on the wood. In response, the EPA acknowledged that “C&D-derived wood can contain de minimis amounts of contaminants and other materials provided it meets the legitimacy criterion for contaminant levels” and thus, did not find it necessary to finalize a de minimis exemption.54 That discussion supports the application of a de minimis principle for this rule for exclusion and removal of contaminants.

    54 See 76 FR 15486 (March 21, 2011).

    The concept of de minimis amounts of material in processed C&D wood is also supported throughout the proposed rule. The Agency noted that C&D wood processing facilities can use a variety of techniques to exclude or remove debris unsuitable for a product fuel and that the processing techniques used may be based on several factors such as: the nature of incoming C&D debris, the extent of material segregation prior to arrival at the processing facility, whether positive or negative sorting is employed, and the scale of the processing facility.55 In addition, C&D processors who provide extensive training for their workers to recognize treated wood tend to be more successful than those processors who do not provide extensive training in excluding or removing treated wood, as evidenced by the Florida study.56 When considering the data submitted for C&D wood, it demonstrates that there is variability regarding levels of contaminants present in processed C&D wood, but that the contaminant levels are well within the range of clean wood and biomass materials for most every contaminant.57 Thus, all of these factors taken together recognize that there invariably will be some amount of unwanted materials that contribute to contaminant concentrations even when using best management practices and trained operators, but that a legitimate product fuel is still produced.

    55 See 71 FR 21011 (April 14, 2014).

    56 See Blassino, Monika, et al. “Methods to Control Fuel Quality at Wood Burning Facilities,” EPA-HQ-RCRA-2013-0110-0033.

    57 Please see the discussion at 71 FR 21014-015 for a detailed explanation of how the Agency initially addressed the specific contaminants: fluorine, lead, pentachlorophenol, and formaldehyde. See also section V.A.4 of this preamble for final Agency determinations.

    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.

    Comment: Management practices for positive sorting are intended to address lead. Data provided to the EPA demonstrates that industry practices appropriately manage lead to ensure that specifications are met and that combustors will meet the limits in their Clean Air Act permits. Nonetheless, the management practices that address lead proposed by the EPA are not opposed when specific clarifications are made to address concerns as requested. The following concerns also apply to the management practices for negative sorting:

    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 . . .”

    Response: First, the Agency disagrees that it is valid to say that industry practices appropriately manage lead. The data submitted to the Agency demonstrate otherwise. As noted in the proposal, there were instances in which isolated samples from Massachusetts (at 407 and 437 ppm) and Wisconsin (at 482 ppm) exceeded the lead levels found in clean wood and biomass (ND-340 ppm). While most of the 224 samples detected lead within the range found in clean wood and biomass, 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. Facilities that had lower levels of lead either did not accept painted wood or required documentation of XRF testing before accepting demolition debris. (See 79 FR 21014, April 14, 2014.) Accordingly, the Agency includes in the regulation the requirement that at least one practice must be used for positive sorting facilities and negative sorting facilities; however negative sorting facilities must also remove fines.

    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 (i.e., CAA section 112 or CAA section 129) are applicable.

    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.58 This shows that the lead elimination options as proposed are in fact achievable.

    58 See revised Appendix A (Revision Submission: April 25, 2013) to letter from Susan Bodine to Suzanne Rudzinski in Docket ID: EPA-HQ-RCRA-2013-0110-0022.

    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 (i.e., handheld gun), thus it is an option for both positive and negative sorters—so that processors can choose to invest in XRF or comply with one of the other lead elimination options. Nevertheless, a determination to finalize the option to use XRF is appropriate regardless of the volume of the input. The point is that, even with high volume input, the lead must be removed.

    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 de minimis amounts of contaminants in the final combusted material. The Agency acknowledges that C&D-derived wood can contain de minimis amounts of contaminants and other materials provided it meets the legitimacy criterion for contaminant levels. Again, to include terms such as “sample” or even “representative sample” in regulatory language gives the perception that the best management practice standard for eliminating lead 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.

    Comment: A commenter stated that facilities [called “chipping and grinding” facilities] which process only clean segregated wood, but that may have to remove de minimis amounts of unwanted material, should not be required to remove fines because the C&D debris fines which may contain contaminants are left behind as a result of the segregation. These chip and grind facilities are permitted to receive and grind “Green Material”, which under California regulations includes acceptable C&D-derived wood as well as other clean cellulosic biomass materials.59

    59 “Green Material” under California law means any plant material that is separate at the point of generation, contain no greater than 1.0 percent of physical contaminant by weight, and meets the requirements of Title 14 CCR, Division 7, Chapter 3.1, Article 7, section 17868.5. Green material includes, but is not limited to yard trimmings, untreated wood wastes, natural fiber products, and C&D wood waste.

    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 de minimis amounts of visible residual physical contaminants such as metal, plastics, and pieces of non-compliant wood that may be present in the green material, typically by hand, in order to meet customers' fuel quality specifications. This quality control measure should not be deemed processing by negative sorting which triggers the requirement to remove fines. Fines removal would be an expensive step at chipping and grinding facilities and is unnecessary because the C&D wood received has already been seperated from the mixed C&D materials and contaminants, including fines, are not present in meaningful amounts. An attachment for five different California chipping and grinding facilities that receive and grind green material, but do not remove fines, show that each facility's fuel meets the NHSM rule's contaminant criterion.60

    60 See Attachment 1 of comment submitted by Covanta Energy Corporation in Docket: EPA-HQ-RCRA-2013-0110-0084.

    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.

    Response: Chip and grind facilities would not be considered negative sorters for purposes of the best management practices for lead under this rule if in fact their sorting operations only involve removal of small or de minimus amounts of unwanted material (as described above) they have received from a source that has segregated/pre-sorted the C&D material through positive sorting. This would be different from the situation in which C&D processors accept and process co-mingled C&D material in a large centralized facility which we discussed in the proposal.

    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).

    d. Specific Requests for Comments i. Pentachlorophenol

    Comment: The proposed requirements for operators to exclude or remove utility poles treated with pentachlorophenol are consistent with industry practices and combustor specifications and thus, no additional requirements are necessary beyond training. Pentachlorophenol treated wood is easily recognizable with visual inspection based on its dark brown color.

    Response: The Agency agrees that the requirement for processors to train operators to identify pentachlorophenol treated lumber (as well as any other treated lumber) as part of the best management practices is sufficient to ensure that these products are excluded or removed from incoming C&D debris. Because sources of pentachlorophenol can be readily identified by color and by shape of the treated wood, no additional conditions other than those specified by the best management practices are necessary.

    Comment: The EPA should allow testing of older, weathered poles for the presence of pentachlorophenol above some preset level, since poles exposed to deterioration from ultraviolet light and precipitation frequently have lower levels of pentachlorophenol and can be burned safely with controls. Levels must be low enough to prevent the formation of dioxin/furans in combustors. The summary for the EPA study “Products of Incomplete Combustion from Direct Burning of Pentachlorophenol-treated Wood Wastes,” (EPA/600/SR-98/013) states that “[t]he tests showed that combustion is an effective method of destroying the pentachlorophenol in the treated wood, with destruction efficiencies higher than 99.99 percent.” Additional processing to meet boiler specifications should be included.

    Response: The Agency disagrees that it should allow testing of older, weathered poles for the presence of pentachlorophenol. The very argument that appropriate controls should be used to allow burning of pentachlorophenol supports the point that the pentachlorophenol is, indeed, a waste and should be burned under CAA section 129 standards. Thus, the comments that pentachlorophenol can be effectively and safely destroyed [emphasis added] (i.e., 99.99 percent destruction and removal efficiency) and dioxin formation can be prevented [emphasis added] when levels are low enough are concessions that pentachlorophenol in the poles is a waste. Combustion for the purpose of destruction is a function of waste combustion units (e.g., boilers burning hazardous waste and incinerators burning hazardous, municipal, or medical wastes), where pentachlorophenol would not be burned as a fuel, but primarily for destruction.

    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.

    ii. Formaldehyde Levels

    Comment: We strongly support the EPA's decision to balance formaldehyde levels with the fuel value of the resinated wood component of C&D wood to allow formaldehyde levels in C&D wood fuel that are somewhat higher than found in coal or biomass. First, when formaldehyde is grouped with other VOCs and SVOCs and compared to the levels of this contaminant grouping in C&D wood, the levels are comparable to coal.61 Second, the only source that we are aware of formaldehyde in C&D wood is resinated wood. The EPA has already recognized that resinated wood is a valuable fuel commodity and has identified it as a non-waste fuel. 40 CFR 241.4(a)(2). The basis for this determination includes the recognition that resinated wood is a valuable fuel source due to its high fuel value relative to other wood. 76 FR 80483.

    61 See revised Appendix A p. 2. (Revision Submission: April 25, 2013) to letter from Susan Bodine to Suzanne Rudzinski available in Docket ID: EPA-HQ-RCRA-2013-0110-0022.

    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 discussed above, it is a component of a product that is a commodity fuel.62

    62 Comments can be found in the rulemaking docket: EPA-HQ-RCRA-2013-0110-0076.1; EPA-HQ-RCRA-2013-0110-0088; and EPA-HQ-RCRA-2013-0110-0083.1.

    Response: The Agency agrees with the overall argument that resinated wood can be burned as a product fuel along with other processed C&D wood. The Agency described two relevant factors in the proposal believed to be appropriate for balancing the higher formaldehyde levels found in processed C&D wood as a result of the inclusion of resinated wood components. First, although formaldehyde levels in processed C&D wood may reach 176.8 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. Second and more importantly, for many combustors, processed C&D wood scraps that include resinated wood components, actually have added value and are either selected for (in the case of positive sorting) or specifically not removed (in the case of negative sorting) because the wood has been kiln-dried prior to use in construction. Kiln-dried wood has a greater heating value than virgin wood, almost double in some cases. Kiln-dried wood also has more consistent moisture content; an equally important benefit to combustors because a consistent fuel improves combustion efficiency and leads to reduced emissions of particulate matter, carbon monoxide, and other organic hazardous air pollutants.

    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.63 The commenter also argued that this is an acceptable approach because the Agency had previously determined that it is technically correct to group VOCs and SVOCs because they behave similarly in combustion units. The rationale behind this grouping approach, however, was to establish emission standards where carbon monoxide serves as a surrogate for measuring total VOC and SVOC emissions.64 Under NHSM, the Agency has previously permitted grouping of total VOCs as well as grouping of total SVOCs, but not for both groups combined for purposes of comparison to a traditional fuel. More relevant however, is that the Agency does not have any information or data indicating that units combusting processed C&D wood also are designed to burn coal or do burn coal. Thus, coal is not an appropriate traditional fuel for comparison under this categorical non-waste listing.

    63 Because there are no data available on formaldehyde levels in coal, the commenters' approach grouped the PAH levels (which are SVOCs) and VOC levels in coal and then compared them to the levels of the same contaminant groupings in C&D wood. See revised Appendix A, p. 2. (Revision Submission: April 25, 2013) to letter from Susan Bodine to Suzanne Rudzinski available in Docket ID: EPA-HQ-RCRA-2013-0110-0022.

    64 See 76 FR 80477 (December 23, 2011) for a broader discussion.

    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.

    iii. CCA-Treated Wood

    Comment: The requirement to train operators to exclude or remove treated wood is adequate, since visual identification via the color, grain, and shape (such as decking or fencing) of pieces works well to remove CCA-treated wood as demonstrated by the data in the record showing that arsenic and chromium levels in C&D wood are comparable to virgin wood.65

    65 April 26, 2013 letter from Susan Bodine to Suzanne Rudzinski, available at Docket ID: EPA-HQ-RCRA-2013-0110-0025.

    Response: The Agency agrees that the requirement to train operators to exclude or remove CCA-treated wood is the most appropriate option and has finalized this as part of the best management practices and as a separate training requirement at 40 CFR 241.4(a)(5)(iii). The Agency also agrees that current data shows that arsenic and chromium levels in processed C&D wood are comparable to levels in clean wood and biomass (see Table 1. Comparison of Contaminants in Clean Wood/Biomass and Processed C&D Wood to section V.A.4 of this preamble), which results from those processors who choose to exclude or remove CCA-treated wood prior to processing. Thus, CCA wood can, and must, be removed efficiently to allow for a determination that the resultant wood is more like a product than like a waste.

    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.

    Comment: The use of additional technology to identify CCA-treated wood, such as XRF guns or PAN indicator stains, would add unnecessary cost and time to the processing of C&D wood. Further, C&D processors that have tried PAN indicator stains have determined that the stains produce false positives and do not truly identify or measure arsenic.

    Response: The decision to require that operators be trained to exclude or remove treated wood (with the exception of resinated wood) as included in the best management practices, is based in part on the results from the Florida study for evaluating sorting technologies 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 stains are limited in application when processing large amounts of C&D debris.

    The Florida evidence demonstrates that processors who train their employees to visually recognize treated wood are successful in excluding or removing CCA-treated wood.66 Therefore, by requiring processors to train their operators as a condition of this categorical non-waste listing, it will ensure that levels of arsenic and chromium in processed C&D wood remain comparable to or lower than levels in clean wood and biomass as more CCA-treated wood is introduced into C&D debris.

    66 Blassino, Monika, et al. “Methods to Control Fuel Quality at Wood Burning Facilities.” Docket ID EPA-HQ-RCRA-2013-0110-0033.

    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.

    iv. Trained Operators

    Comment: The only elements of training that are appropriate for regulation are identification of the best management practices, not the details of how or by whom the training is provided. Processors should be free to design training programs that work for the individual processors.

    Response: The Agency agrees that the elements of a training program for processors should not be prescribed by the Agency for the C&D processing industry. The Agency's decision to not prescribe specific elements of a training program is based on information in the record that discusses the variability within the C&D processing industry and the ability of trained operators to remove the waste materials from the incoming C&D debris (79 FR 21013, April 14, 2014). Variability refers to the origin of the material, the amount of material segregation prior to arrival at a processing facility, whether positive or negative sorting is used, and the scale of the processing facility.

    Rather than prescribing training requirements that may not be applicable to all C&D processing facilities (i.e., a “one size fits all” approach), the better option is to provide flexibility for processors to choose how to train their operators. The Agency has determined that the regulatory language finalized at 40 CFR 241.4(a)(5)(iii) provides the flexibility needed, but also ensures that C&D processing facilities have trained their operators in accordance with the best management practice requirements such that the resultant material is not discarded when combusted and is, therefore, not a waste.

    Comment: The EPA should specify minimum training requirements and develop requirements similar to those found in the waste combustor rules (New Source Performance Standards for small municipal waste combustion units at 40 CFR 60.1155). These provisions address who is to be trained, when the training must occur by, and what information must be included in the facility-specific training material. It would be difficult for C&D processing facilities to implement a training program without at least minimum requirements set forth in the rule. Further, combustors and state air agencies must have some way to determine if the “trained operator” requirement has been met.

    Response: The Agency does not agree that prescriptive requirements should be developed for C&D processors that are similar to the training standards for small municipal waste combustors. The standards identified in Part 60 for small municipal waste combustors are specific to the operation of a combustion unit, which is a very technical operation with regard to combustion engineering, equipment, and environmental compliance (e.g., air pollution control requirements) obligations, and thus are appropriate for that industry. Such specificity and degree of training is not necessary for the C&D processing industry because its operations are not technologically comparable. Thus, processors can develop a training program that meets their specific needs, but that also ensures, through required training (and best management practices), that the processed C&D wood material is not discarded when combusted and is, therefore, not a waste.

    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.”

    Comment: In response to solicitation for comment on whether processors would be required to keep records as a condition of the categorical listing to demonstrate that such operators have been formally trained, one comment requested that C&D processors be required to maintain records of the training they have received, similar to the requirements found in waste combustor rules (New Source Performance Standards for small municipal waste combustion units at 40 CFR 60.1355). These provisions require records showing dates of completion of the training course, documentation showing completion of the training course, and records of review of the training materials.

    Response: The Agency agrees that a condition is necessary to document that operators have been formally trained so that processors are accountable to their customers when certifying that they have used trained operators. Thus, separate requirements for processors to conduct training and maintain records of the training are finalized at 40 CFR 241.4(a)(5)(iii). This requires that processors train their operators to exclude or remove the materials as listed in paragraph (a)(5) from the final product fuel. Although not as prescriptive as the waste combustor rules for similar reasons as discussed above, the Agency has determined that the following is adequate for demonstrating compliance with the trained operator requirement: records of training must include date of training held and must be maintained on-site for a period of three years.

    Comment: Training requirements should only apply to the final processing facility, which is responsible for the quality of the final product fuel and with whom the combustor has a contract or purchasing relationship. C&D wood may be partially sorted at various C&D sites, then sent to centralized site for final processing and thus, the upstream facilities should not be subject to training requirements.

    Response: The Agency agrees that only those processors who conduct the final processing steps and are responsible for the quality of the final product fuel, should be required to train their operators. Any processor who pre-sorts in preparation for further processing at another facility would not need to implement a training program for its operators. It is the final processor who must ensure and certify that processing has transformed the processed C&D wood into a non-waste product fuel according to best management practices.

    v. Written Certification

    Comment: Purchase agreements between the provider of the C&D wood product and combustor provide sufficient records related to the quality of the product fuels being combusted at a facility. There is no need to increase the burden on regulated sources by requiring additional paperwork in the form of a written certification and personnel resources for a duplicative task. In addition, the EPA does not need to prescribe the form of the written certification because purchase agreements and contracts are common and provide sufficient documentation.

    Response: The Agency agrees that purchase agreements (or contracts) can provide records related to quality of the fuels being combusted at a facility. These documents indicate the commitments of the processor to meet the specifications and to provide quality processed C&D wood. The proposed rule suggested that such agreements can serve as the written certification document, but requested comment on whether a written certification statement, in addition to the contract/purchase agreement, would be clearer and more effective (79 FR 21016, April 14, 2014).

    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.

    Comment: The EPA should prescribe what suffices for the “written certification.” At a minimum, it is recommended that the written certification include the specific management practices that the processor has undertaken. The written certification requirement should also specify how often the combustor must obtain the certification, whether it is once per load, one certification for each supplier, or in some other manner or frequency. Specific criteria for the certification should also include a requirement for an independent third party to routinely sample the processed C&D wood as part of an ongoing sampling program, and made it a requisite for the written certification.

    Response: The Agency disagrees that the processor should be required to include the specific best management practices undertaken in its certification, since the best management practices in 40 CFR 241.4(a)(5) are applicable to all processors. The only distinction is between the lead exclusion/removal options for positive and negative sorters, which provide equivalent assurance that lead levels in processed C&D wood are comparable to or less than clean wood and biomass.

    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.67 The data demonstrate that processors using best management practices are meeting the legitimacy criteria absent a regulatory requirement. The extent to which some processors may not be meeting the legitimacy criteria is remedied by imposing the conditions for certification and training to identify contaminated materials in the rule. The Agency has determined that application of the best management practices at 40 CFR 241.4(a)(5), the written certification, and training record provides sufficient assurance.

    67 A state may choose, however, to require a third party sampling program as an additional condition of this categorical non-waste listing.

    Comment: A number of state air permits already prohibit the use of C&D debris as a fuel type. Under the proposed amendments, these permits would need to be reopened, public noticed, and be made practically enforceable.

    Response: The Agency agrees that if a combustion facility would choose to burn C&D wood as a product fuel under this categorical non-waste listing, the facility's permit would need to be reopened to include the processed C&D wood as a fuel type. The combustor would be responsible for documenting the C&D wood's non-waste status according to 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.

    Comment: The presumption is that air permits will need practically enforceable requirements addressing the proposed written certification provisions. The EPA should consider how the written certification would be enforceable for a small combustion unit that does not qualify for an air permit.

    Response: We are adopting in this final action the approach discussed in the proposal at 79 FR 21016, under which the written certification must be included as part of the contract, purchase agreement, or other legally binding document between the processor and the combustor. This documentation will also be considered a “record” which satisfies the record keeping requirements of section 60.2740(u) (Emissions Guidelines) and section 60.2175(w) (New Source Performance Standards) for CISWI units and section 63.11225(c)(2)(ii) for area source boilers and section 63.7555(d)(2) for major source boilers. Each of these provisions contains a reference specific to categorical non-waste determinations under section 241.4 which read: “[f]or operating units that combust non-hazardous secondary materials as fuel per section 241.4 of this chapter, you must keep records documenting that the material is listed as a non-waste under section 241.4(a) of this chapter.” The requirement to document and keep a record exists within the Federal air regulations and in this case, the record is the written certification included within the contract, purchase agreement, or other legally binding document. The air regulations referenced in this paragraph are enforceable either through air permits when incorporated or are separately enforceable under the CAA. Thus, an air permit is not necessary to make a requirement enforceable.

    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 (i.e., sections: 60.2740(u), 60.2175(w), 63.11225(c)(2)(ii), or 63.7555(d)(2)).

    Comment: Combustors who process C&D wood for their own combustion should be allowed to self-certify that they have complied with the best management practices.

    Response: The Agency agrees that the ability to self-certify when the combustor is also the processor is appropriate. However, in the absence of a contract or purchase agreement, the combustor still must certify that the processed C&D wood has been sorted by trained operators in accordance with best management practices. A combustor who is also the processor is still subject to the requirements and conditions of this categorical non-waste listing. As the processor, the requirement to certify that the processed C&D wood has been sorted by trained operators in accordance with best management practices is applicable per 40 CFR 241.4(a)(5)(iv). The training requirement is applicable per 40 CFR 241.4(a)(5)(iii). As the combustor, the requirement to maintain the written certification statement as part of its records is applicable regardless of whether or not there is a contract or purchase agreement. If an inspection by a regulatory authority reveals that these requirements have not been met, then the combustor could face enforcement action.

    Comment: The EPA should consider that those who pre-sort C&D wood should not be required to provide certifications, as long as they are providing wood to C&D processors that meet the requirements of 40 CFR 241.4(a)(5). Similarly, in cases where C&D wood is processed by more than one processing facility, the certification requirements should only apply to the final processing facility.

    Response: The Agency agrees that the written certification requirement should only apply to the final processor, as is the case for only the final processors to use trained operators. The processors conducting the final processing steps are responsible for the quality of the final product fuel and for ensuring that processing has transformed the processed C&D wood into a non-waste product fuel according to best management practices under 40 CFR 241.4(a)(5). Thus, any processor who pre-sorts in preparation for further processing at another facility would not need to provide a written certification to the combustor. However, the materials at the intermediate processor facilities would still be solid wastes.

    e. Cement Kilns Using Processed C&D Wood

    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.

    Comment: Cement kilns, in particular, are capable of handling a wide variety of fuels without the need for the extensive processing that some other types of combustion facilities require. Processing of C&D wood need only be to the extent necessary to meet the requirements of the receiving combustion unit. PCA accepts that removing certain material is necessary to render the non-waste fuel “legitimate,” but for cement kilns several of the listed items, such as plastics and paper, are beneficially used in the process. Therefore, it is not necessary to remove all listed materials due to the unique and inherent characteristics of the cement production process. Defining which materials must be removed and the extent to which they need to be removed should be a function of the unit receiving and combusting the processed fuels.

    Response: The Agency disagrees with this comment. Although cement kilns can burn a wide variety of materials as fuel regardless of Btu value and contaminants present, it also lends support for regulating such cement kilns under the CAA section 129 standards so that they can appropriately control emissions from these waste-like fuels. This is not an argument for rendering the materials to be product fuels. Rather, when evaluating whether an NHSM can be a legitimate product fuel, discard (i.e., if the material has been discarded in the first instance, then it must be sufficiently processed) and the legitimacy criteria are the determinants, not the capabilities of the unit burning the NHSM.

    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).

    Comment: With respect specifically to lead in C&D wastes, PCA encourages the EPA to establish processing criteria (in-lieu of the case-by-case legitimacy test) that allow lead to be present at levels that are comparable to the traditional fuels for the receiving combustion unit. There is variation in the capabilities and other environmental restrictions of facilities using C&D categorical non-waste fuel, and cement kilns in particular have the ability to use a wider variety of fuels. Also, when metals contaminants are grouped, the lead levels indicated in the variety of C&D in the proposed rule are not significantly higher than traditional fuel groupings. See (attached) Table 1 of EPA-HQ-RCRA-2013-0110-0081.68 As a demonstration of the balancing factors specific to cement kilns, there is a significant body of data and knowledge on the fate of metals in a cement kiln system that documents the fate of semi-volatile metals (SVM) and low volatile metals (LVM) that enter the kiln system through minor concentrations in the raw feed and fuels. The LVMs and other pollutants with similar properties are directly incorporated into the clinker being produced.

    68 See Table 1 attached to PCA's comments on the proposed rule, Docket ID: EPA-HQ-RCRA-2013-0110-0081.

    Response: Again, when evaluating whether an NHSM can be a legitimate product fuel, it is discard and the legitimacy criteria that are the determinants, not the capabilities of the unit burning the NHSM. In this categorical listing, the pertinent criterion is whether the lead concentration, or any other contaminant concentration, in processed C&D wood is comparable to or lower than the contaminant concentrations in clean wood and biomass. The fact that cement kilns can burn contaminated, low value fuel does not automatically qualify them for this categorical non-waste listing.

    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,69 it is evidence that contaminants are not comparable even when grouped, and therefore processing according to best management practices must occur to exclude or remove specific contaminants (i.e., lead) so that the concentrations in processed C&D wood would be comparable to solid traditional fuels, assuming that this was the appropriate traditional fuel comparison for this listing. All C&D processors must, however, conduct processing according to the best management practices to ensure a legitimate product fuel is consistently produced, regardless of the type of combustion unit that will burn the processed C&D wood.

    69 For a discussion of “small acceptable range” with regard to contaminant comparisons, see 76 FR 15523-24, (March 21, 2011).

    Comment: Removal of utility poles from the C&D fuel stream is not necessary for cement kilns when considering balancing factors, and especially an organic constituent grouping comparison. Cement kilns are designed and operated to effectively use a variety of fuel streams under well-controlled conditions and the APCD temperature control used in kiln operations ensures that dioxin (the contaminant of concern which can be generated during combustion of pentachlorophenol) emissions are controlled.

    Response: The Agency disagrees with this comment for the reasons discussed in previous responses. It is a basis for saying that the cement kilns burning this material or other contaminated materials as fuel(s) should have permits under section 129 of the CAA so that they can appropriately control emissions under the CISWI standards. This is not an argument for rendering the materials to be product fuels. Again, the information provided to illustrate that cement kilns are highly-efficient combustors and that the resulting contaminants are either completely combusted, chemically incorporated into the clinker being produced, or captured in the kiln system air pollution control device are not relevant considerations for this categorical non-waste listing. In order to comply with this categorical listing, all C&D processors must conduct processing according to the best management practices to ensure a legitimate product fuel is consistently produced, regardless of the type of combustion unit that will burn the processed C&D wood.

    B. Paper Recycling Residuals Used as Fuel at Paper Recycling Mills

    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.

    1. Detailed Description of Paper Recycling Residuals

    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 magazines, newspaper, office paper, and old corrugated containers obtained through various commercial and residential recycling programs or purchased from retail establishments.70 Some paper recycling mills' feedstock is limited solely to old corrugated containers. The primary purpose of the paper recycling manufacturing process is to generate recovered fibers used to make new paper and paperboard products. The process also generates PRRs that are secondary materials not suitable for making new paper products, but are landfilled, sent for metals recycling, or used as a fuel.71

    70 See Attachment 4, page 1, footnote 2 of AF&PA's Comments to Docket: EPA-HQ-RCRA-2008-0329-0871.

    71 Because the incoming feedstock may contain a number of other materials, including metals, metals may also be recovered and sent for recycling.

    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, i.e., the material is handled as a valuable commodity (whether used on-site or shipped off-site to other paper recycling mills); the material has meaningful heating value; and the material contains contaminants that are comparable to or lower than the traditional fuels the units were designed to burn.

    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.72 Although there are over 100 paper recycling mills across the U.S., the majority of mills' boilers use natural gas and cannot burn solid fuels. As a result, PRRs generated in their processes generally are landfilled. At any particular paper recycling mill capable of burning PRRs (i.e., their boilers burn solid fuel), between 55 to 100 percent of the PRRs generated on-site are burned and may represent between 20 to 25 percent of the total solid fuel burned in their solid fuel boilers. Of the 30 percent of PRRs burned as fuel, no more than 5 percent is burned off-site.73 For the PRRs burned off-site, the proposal stated that in two cases they have been used to supplement other fuels burned at a commercial cogeneration plant 74 and a commercial biomass gasification plant.75 However, the information regarding off-site use is based on only these two cases and the Agency lacks sufficient detail to determine that PRRs, when sent off-site for energy recovery, other than to those paper recycling mills within the industry that burn solid fuels (as discussed below), continue to meet the legitimacy criteria and are not discarded.

    72Generation, Management, and Processing of Paper Processing Residuals. Industrial Economics Corporation, October 26, 2012. This is posted within the docket for the final rulemaking (Docket: EPA-HQ-RCRA-2013-0110).

    73Generation, Management, and Processing of Paper Processing Residuals. Industrial Economics Corporation, October 26, 2012. This is posted within the docket for the final rulemaking (Docket: EPA-HQ-RCRA-2013-0110).

    74 A cogeneration plant is one that generates electricity and useful heat (instead of releasing it into the environment via cooling towers, for example) for heating purposes either on-site or for use nearby.

    75 National Council for Air and Stream Improvement, Inc. Technical Bulletin (TB) No. 806, “Beneficial Use of Secondary Fiber Rejects,” pp. 10-11. See attachment to AF&PA Comments to Docket, August 3, 2010 (docket document ID number: EPA-HQ-RCRA-2008-0329-0871).

    The Agency previously understood PRRs to be a term industry commonly used to refer to Old Corrugated Container (OCC) rejects.76 Since publication of the March 21, 2011 NHSM final rule and the December 23, 2011 proposal, however, the Agency has received comments more appropriately identifying OCC rejects as a subset of the PRR universe. Specifically, the term “OCC rejects” refers to only one grade of recovered fiber, whereas PRRs used as fuel encompass residuals from all types of fiber grades. Therefore, in the proposal as well as in the final rule, the Agency is including OCC rejects within the broader PRR universe in a categorical non-waste determination.

    76 Another term industry often uses when referring to OCC rejects is “recycling process residuals” which was identified in the March 21, 2011 final rule (76 FR 15486).

    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.

    2. PRRs Under Previous NHSM Rules a. March 21, 2011 NHSM Final Rule

    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 are not discarded and not solid wastes. The EPA has determined for this final rule, as discussed further below, that these legitimacy criteria are indeed met for OCC rejects and are also met for certain other types of PRRs and, under the conditions of the final rule, these PRRs (including OCC rejects) can be burned under Clean Air Act section 112.

    b. February 2013 NHSM Final Rule

    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.77 Based upon the information received at that time, we stated that the information supported the categorical listing of PRRs as a non-waste fuel burned on-site. For PRRs transferred off-site for use as a fuel, we requested information regarding how and where they are burned and whether they are managed as a valuable commodity. We also stated that if the information submitted supports off-site use as a fuel, the Agency may include those PRRs in a subsequent rulemaking.78

    77Generation, Management, and Processing of Paper Processing Residuals. Industrial Economics Corporation, October 26, 2012.

    78 78 FR 9111, February 7, 2013 (page 9173).

    3. Scope of the Proposed Rule and Final Categorical Non-Waste Listing for Certain PRRs

    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 “Paper recycling residuals means the co-product material generated from the paper recycling process and is composed primarily of wet strength and short wood fibers that cannot be used to make new paper and paperboard products. The term paper processing residuals also includes fibers from old corrugated container rejects.”

    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 79 rather than co-products, generated from the recycling of paper, paperboard and corrugated containers.

    79 Secondary materials are materials that are 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.

    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: “Paper recycling residuals means the secondary material generated from the recycling of paper, paperboard and corrugated containers, composed primarily of wet strength and short wood fibers that cannot be used to make new paper and paperboard products. Paper recycling residuals that contain more than small amounts of non-fiber materials including polystyrene foam, polyethylene film, other plastics, waxes and adhesives, dyes and inks, clays, starches and other coating and filler material are not paper recycling residuals for purposes of this definition.”

    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.

    4. Rationale for Final Rule

    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.

    a. Discard

    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.

    i. Generation of PRRs in the Paper Recycling Manufacturing Process

    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 (i.e., wet strength and short wood fibers), which make-up the largest portion of PRRs that would eventually be used as a fuel. These PRRs may be consolidated with those generated from the junk tower and drum screen, and sent across a dewatering screen or a screw or ram press to improve both ease of handling and heating value.

    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.80 These PRRs would then be consolidated with the PRRs generated in the preceding step before being conveyed to the combustion source where they are blended with traditional fuels and fed to the combustor.

    80 AF&PA Technical Bulletin, Attachment 4, Recycling Process Residuals, p 2. September 10, 2009.

    Thus, PRRs are generated at various steps of the paper recycling process, with the second step producing the bulk of PRRs (i.e., unsuitable fibers) destined for use as a fuel. Other non-fiber reject material (i.e., clays, starches, waxes and adhesives, other plastics, filler and coating additives, and dyes and inks) contained in the PRRs would be considered to have a lower heating value than the unsuitable fibers (see meaningful heating value discussion section V.B.4.b. of this preamble). All that is generally required for use of PRRs as a fuel after screening of non-fiber material that cannot be used to make paper or paperboard products is removal of moisture to increase the Btu value. Removal of moisture can range from simply allowing PRRs to drain freely (e.g., for coarse and heavy PRRs) to sending them through a press (e.g., for smaller and compressible 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.

    ii. Off-Site Combustion of PRRs as Fuel

    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. Thus, we have determined that such off-site use does not constitute discard.

    b. Legitimacy Criteria

    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.

    i. Managed as a Valuable Commodity

    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 (i.e., from the container, PRRs can be fed directly to the boiler) or convey them to a storage pile of traditional solid fuels where they are comingled prior to burning. Other paper recycling mills convey PRRs directly to the fuel feed systems. This demonstrates that PRRs are handled promptly and are managed as a valuable commodity, such that, after generation on-site, they are fed directly to the boiler, or, when not used immediately, they are managed in containers and storage piles along with traditional fuels used on site.

    For PRRs utilized as a fuel at off-site paper mills, PRRs are managed similarly to those generated on-site.81 These mills store PRRs in containers until sufficient quantities are accumulated for transfer (generally not more than several weeks). Upon arrival at the combustion mill, the material is managed as described above for on-site generated PRRs. Because storage does not exceed reasonable time frames, and management is similar to that of traditional fuels, the Agency has determined that PRRs burned on-site, as well as at off-site paper mills, meet this legitimacy criterion. To the extent PRRs do not meet these general standards for being handled as a valuable commodity, for example by being allowed to accumulate at the combustor or the applicable site for unreasonable lengths of time not normally done within the industry, the categorical listing would not apply.

    81 American Forest and Paper Association phone communication to EPA, November 11, 2014 included in the docket to the final rule.

    ii. Meaningful Heating Value and Used as Fuel to Recover Energy

    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).82 Although this is lower than the general guideline of 5,000 Btu/lb as fired, the Agency has previously stated that a person may demonstrate meaningful heating value below 5,000 Btu/lb if the energy recovery unit can cost effectively recover meaningful energy from the NHSM (76 FR 15522, March 21, 2011). For PRRs, industry has stated that paper recycling mills' boilers can cost effectively recover energy at such heating values because of the boiler design. Specifically, 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 combustion, which often have over-fire and/or under-grate air that assists in the efficient burning of wetter fuels. This allows paper recycling mills to burn clean cellulosic biomass fuels, such as hog fuel and bark, which is the primary fuel, as well as PRRs that have varying degrees of moisture content. 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. Industry also stated that PRRs are 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 (i.e., whether simply draining freely versus pressed), amount of solids, fiber content, presence of non-fiber packing materials, and combustion conditions necessary for the effective operation of the boilers.83

    82 See AF&PA Comments, p 62, to Docket document ID: EPA-HQ-RCRA-2008-0329-0871.

    83 See “AF&PA-AWC Responses to EPA's Questions on PRR and Railroad Ties (May 2013).”

    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.84 Therefore, 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.85

    84 December 2011 boiler database—Boiler Reconsideration Proposal Databases: Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, & Fuel Analysis Data Reported under ICR No. 2286.01 & ICR No. 2286.03 (version 7); http://epa.gov/ttn/atw/boiler/boilerpg.html. Data presented is for paper manufacturing facilities with NAICS code #322 and where fuel type indicates it refers to the repulped paper fibers that are used as fuels and include: “dewatered combustible residues,” “hydro pulper refuse,” “OCC rejects,” “recycle fiber lightweight rejects,” and “recycled fiber.”

    85 In determining compliance with this legitimacy criterion (i.e., average value of 3,700 Btu/lb) the Agency anticipates, for PRRs generated on-site, that boiler operators will use generator knowledge in combination with testing on an as needed basis, to determine Btu value of the PRRs to be burned. For PRRs sent off-site to another paper recycling mill boiler, the receiving boiler also may rely on generator knowledge and testing, but may need to test more frequently based on the consistency of the PRRs composition from each of the generating mills.

    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.

    iii. Contaminants Comparable to or Lower Than Traditional Fuels

    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 combusted both on-site and offsite.86 See Table 2 of this preamble.

    86 In response to the ANPRM, commenters submitted data for OCC rejects, which show that OCC rejects meet the contaminant criterion.

    TABLE 2—Comparison of Contaminants in Paper Recycling Residuals (PRRs) and Traditional Fuels Contaminants a Clean wood/biomass Coal b range PRRs cd Arsenic ND-298 ND-174 0-17.7 Chromium ND-340 ND-168 <0.17-26.9 Lead ND-340 ND-148 <0.10-21.1 Mercury e ND-1.1 ND-3.1 ND-0.0724 Chlorine ND-5400 ND-9,080 <9.8-7310 Sulfur ND-8700 740-61,300 237-2500 Antimony ND-26 ND-10 0.07-0.9 Beryllium ND-10 ND-206 0.005-0.329 Cadmium ND-17 ND-19 0.03-7.1 Cobalt ND-213 ND-30 1.05-1.99 Manganese ND-15,800 ND-512 <0.10-21.1 Nickel ND-540 ND-730 <0.27-25 Selenium f ND-9 ND-74.3 ND-3.29 Fluorine g ND-300 ND-178 <17-<26 a All units expressed in parts per million (ppm) on a dry weight basis. b Coal and Biomass data taken from the EPA document Contaminant Concentrations in Traditional Fuels: Tables for Comparison, November 29, 2011, available at www.epa.gov/epawaste/nonhaz/define/index.htm. Refer to document for footnotes and sources of the data. c December 2011 boiler database—Boiler Reconsideration Proposal Databases: Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, & Fuel Analysis Data Reported under ICR No. 2286.01 & ICR No. 2286.03 (version 7); http://epa.gov/ttn/atw/boiler/boilerpg.html. Data presented is for paper manufacturing facilities with NAICS code #322 and where fuel type indicates it refers to the repulped paper fibers that are used as fuels and include: “dewatered combustible residues,” “hydro pulper refuse,” “OCC rejects,” “recycle fiber lightweight rejects,” and “recycled fiber.” d CAA 112 Hazardous Air Pollutant (HAP) compounds (e.g., benzene, PAHs) data was not collected in this data set. HAP compounds may be present. e Other PRR sample results indicate mercury was non-detect at 0.1 ppm; therefore, some samples could have been between the highest recorded value of 0.0724 ppm and the non-detect limit of 0.1 ppm. f Other PRR sample results indicate that selenium was non-detect at 7 ppm; therefore, some samples could have been between the highest recorded value of 3.29 ppm and the non-detect limit of 7 ppm. g Fluorine was not detected in any samples; the highest non-detect level is listed.

    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.87 For purposes of comparability, a total constituent analysis for toluene would yield a concentration of up to 0.08 mg/L (or 0.08 ppm), assuming worst case conditions, which is well below the concentration found in coal at 8.6—56 ppm.88 89 Likewise, the EPA has no reason to find that results would be any different from the broader universe of PRRs, since the steps that generate PRRs, which must process multiple grades of recovered fibers, are equivalent to or more rigorous than those that generate only OCC rejects (i.e., where the feedstock is limited to OCCs).

    87 National Council for Air and Stream Improvement, Inc. Technical Bulletin (TB) No. 806, “Beneficial Use of Secondary Fiber Rejects,” Appendix B, Table B1. TCLP Analysis of OCC Rejects. See attachment to AF&PA Comments to Docket, August 3, 2010 (document ID number; EPA-HQ-RCRA-2008-0329-0871).

    88 Section 1.2 of Method 1311 (Toxicity Characteristic Leaching Procedure) allows for a total constituent analysis in lieu of a TCLP analysis. That is, the Agency allows calculating a solid phase's maximum theoretical concentration expected in a TCLP extract by dividing a sample's total constituent concentration by 20, representing 20:1 liquid-to-solid ratio (by weight) employed in the TCLP procedure. See http://www.epa.gov/osw/hazard/testmethods/faq/faq_tclp.htm. While leaching extract concentrations do not reflect total constituent concentrations, multiplying the extract concentration (0.004 ppm) by 20 provides the minimum total concentration in the waste. However, because toluene is somewhat soluble in water (515 mg/L at 20° C), the leaching extract concentration multiplied by 20, is for this constituent, a reasonable approximation of the total toluene concentration. Water solubility data can be found at: http://www.epa.gov/chemfact/s_toluen.txt.

    89Concentrations in Traditional Fuels: Tables for Comparison, November 29, 2011, available at www.epa.gov/epawaste/nonhaz/define/index.htm and in the docket (EPA-HQ-RCRA-2008-0329).

    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 in addition burn coal if the unit is designed to burn that solid fuel.

    5. Summary of Comments Requested

    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.

    Meaningful heating value. Although the heating value is less than the general benchmark of 5,000 Btu/lb, the Agency determined that PRRs meet the meaningful heating value criterion since paper recycling mills have demonstrated that they can cost effectively recover energy from those materials. The Agency requested information regarding the percentages of non-fiber materials that typically make-up PRRs; such information would be useful in understanding the variability of the PRR's heating value since PRRs that contain a larger portion of wood fibers could be expected to have a higher heating value. Those non-fiber materials consist of light reject material captured in fine screens remaining after the processing steps described in section V.B.1. of this preamble and consist of polystyrene foam, polyethylene film, other plastics, waxes and adhesives, dyes and ink, clays, starches, and other filler and coating additives.

    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.

    Other discarded materials. Although the data provided in the boiler database regarding the level of contaminants in the PRRs indicate that they meet the contaminant legitimacy criterion, evaluations conducted for the development of the boiler database suggested that, in a few cases, OCC rejects used as feedstock at paper recycling mills contain other discarded materials. For example, some paper recycling mills may accept cardboard containers from off-site that have not been completely emptied of their contents or otherwise are contaminated with foreign materials. The Agency was interested in receiving information regarding how common this practice is, the composition of the contents/materials, any precautions taken to ensure that the contents/materials do not contribute to unacceptable contaminant concentrations, and whether any additional conditions should be imposed to ensure that such cardboard containers have been emptied. In other words, any remaining contents/materials should only be incidental.

    Based on information received, and examination of the few cases in the boiler database of foreign materials present in OCC rejects undergoing recycling,90 the Agency concluded that such situations are incidental, and no specific conditions to ensure the containers are empty are warranted, other than to describe the incidental contamination as part of the categorical listing.

    90 December 2011 boiler database—Boiler Reconsideration Proposal Databases: Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, & Fuel Analysis Data Reported under ICR No. 2286.01 & ICR No. 2286.03 (version 7); http://epa.gov/ttn/atw/boiler/boilerpg.html.

    PRRs burned off-site. The Agency considered whether to expand the categorical listing to include PRRs that are burned as a fuel product off-site. According to earlier comments submitted on previous NHSM rulemakings, OCC rejects have been used as a supplemental fuel in two plants: a commercial biomass gasification plant and a commercial cogeneration plant (where OCC rejects provide 3 to 4 percent of the total fuel input at the latter plant).91 An intermediary company takes the OCC rejects from three mills and processes them by removing large pieces of plastic, shredding, and drying the remaining residuals and delivers the OCC reject fuel to the plants.92 Thus, contrary to what the Agency previously concluded based on the information it had at the time of the March 21, 2011 final rule,93 in these two instances, the OCC rejects burned off-site in commercial power plants can be managed more like a non-waste fuel than a waste fuel.

    91 In the December 23, 2011 final NHSM rule (76 FR 15487), the agency previously believed these facilities to be municipal or commercial incinerators. Subsequent comments have identified these facilities to be commercial biomass and cogeneration plants.

    92 National Council for Air and Stream Improvement, Inc. Technical Bulletin (TB) No. 806, “Beneficial Use of Secondary Fiber Rejects,” pp. 10-11. See attachment to AF&PA Comments to Docket, August 3, 2010 (document ID: EPA-HQ-RCRA-2008-0329-0871).

    93 The Agency had stated that limited information indicated that OCC rejects are “burned in municipal or commercial energy facilities (which appear to be municipal or commercial incinerators) and thus, would clearly indicate discard . . .” 76 FR 15487.

    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 i.e., they are legitimately burned for fuel in solid fuel boilers that are designed to burn wet fuels, with mills optimizing their operation around boiler design. Thus, we have determined that such use does not constitute discard.

    6. Responses to Comments a. Specific Request for Comments i. Meaningful Heating Value

    Comment: The EPA appropriately determined that PRRs have meaningful heat value and are burned as a fuel to specifically recover energy in solid fuel boilers at paper recycling facilities. Mill boilers are specifically designed to produce heat by combusting materials such as PRRs and use wet fuels to regulate temperature. Since virgin biomass, as fired, can contain up to 60 percent moisture and have BTU values as low at 3,500 MMBtu/lb, there should be no Btu threshold for PRRs.

    Response: The EPA finds that the data in the record and the description of the combustion process of the particular boilers used in the paper recycling industry confirms that paper mill boilers cost-effectively recover energy from PRRs used as fuel, thus meeting the meaningful heating value criterion.

    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 (i.e., whether simply draining freely versus pressed), amount of solids, fiber content, presence of non-fiber packing materials, and combustion conditions necessary for the effective operation of the boilers.94

    94 See “AF&PA-AWC Responses to EPA's Questions on PRR and Railroad Ties (May 2013).”

    To further understand the variability of the PRR's heating value, the Agency requested information regarding the percentages of non-fiber materials (e.g., polystyrene foam, polyethylene film, other plastics, waxes and adhesives, dyes and inks, clays, starches, and other filler and coating additives, etc.). As discussed in section V.B.4. of this preamble, while unsuitable paper fibers (i.e., wet strength and short wood fibers), make up the largest portion of PRRs destined for fuel use, PRRs also contain these non-fiber materials that cannot be used to make paper or paperboard products. PRRs that contain a larger portion of wood fibers could be expected to have a higher heating value.

    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 (i.e., consist predominantly of clays, pigments and inorganic fillers, which have little or no heat content). Combustion of more than small amounts of these materials which have low heating values constitute discard and thus burning of a waste fuel. The Agency has revised 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. (See also comment response regarding PRR definition below.)

    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.95

    95 In determining compliance with this legitimacy criterion (i.e., average value of 3,700 Btu/lb) the Agency anticipates, for PRRs generated on-site, that boiler operators will use generator knowledge in combination with testing on an as needed basis, to determine Btu value of the PRRs to be burned. For PRRs sent off-site to another paper recycling mill boiler, the receiving boiler also may rely on generator knowledge and testing, but may need to test more frequently based on the consistency of the PRRs composition from each of the generating mills.

    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 96 shows that five of the eight facilities (that included moisture content and heating value data) have as-received heating values greater than 3,700 Btu/lb with an average per facility of 3915 Btu/lb. Review of facilities combusting PRRs in the Boiler MACT Database indicates six of eleven facilities have PRR as-received heating values equal to or greater than 3700 Btu/lb with an average per facility of 4777 Btu/lb (in other terms, 30 of 55 unique data points are above 3,700 Btu/lb).

    96 NCASI Technical Bulletin 806 included in docket number EPA-HQ_RCRA-0329-0871.

    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.

    ii. Other Discarded Materials

    Comment: A commenter noted that the proposal stated that evaluations conducted for the development of the boiler database suggested that, in a few cases, OCC rejects being recycled contain other discarded materials. For example, some paper recycling mills may accept cardboard containers from off-site that have not been completely emptied of their contents or otherwise are contaminated with foreign materials. The Agency was interested in receiving information regarding how common this practice is, the composition of the contents/materials, any precautions taken to ensure that the contents/materials do not contribute to unacceptable contaminant concentrations, and whether any additional conditions should be imposed to ensure that such cardboard containers have been emptied.

    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 97 to assure the quality of the bales of recovered fiber received. There are practices in place to reduce the likelihood of contamination in the incoming bales. In isolated instances where bales contain unwanted materials, the bale may be rejected; the bale may be accepted but rejected after further inspection; or the bale may be used and the contaminants removed during processing. Given the amount of water and fiber that are processed together, it is unlikely that the contaminants would be at a level of concern. Rejected bales and boxes are sent to a landfill and are not used as fuel. Additional testing requirements are in place to assure that packaging is of suitable purity for mills producing recycled paper that will be used for food-contact packaging.

    97 Standard specifications for buying and selling of materials issued by the Institute of Scrap Recycling Industries Inc.

    Response: The Agency disagrees that the presence of foreign materials in OCC rejects undergoing recycling should not be of concern. Combustion of such materials remaining in the PRRs after recycling constitute burning of a solid waste; and as such, units burning those materials would be subject to CAA section 129 standards. Information received from commenters states that the inspection practices described above prevent the introduction of other discarded materials and are standard practice. Based on that information, and examination of the few cases in the boiler database of foreign materials present in OCC rejects undergoing recycling,98 the Agency has concluded that such situations are incidental, and no specific conditions to ensure the containers are empty are warranted, other than to describe the incidental contamination as part of the categorical listing. The Agency reiterates, however, that the combustion of discarded materials in PRRs would result in the application of the CAA section 129 standards.

    98 December 2011 boiler database—Boiler Reconsideration Proposal Databases: Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, & Fuel Analysis Data Reported under ICR No. 2286.01 & ICR No. 2286.03 (version 7); http://epa.gov/ttn/atw/boiler/boilerpg.html.

    iii. Combustion Off-Site

    Comment: Under D.C. Circuit precedent, the use of PRRs by the paper industry should not be treated any differently from the use of the PRRs by the generator. AMC I, at 1186, 1192-93 (materials recycled in an ongoing industrial process are not discarded and materials that are destined for beneficial use by the generating industry itself are not waste because such materials are not part of the waste disposal problem). Mills that do not combust solid fuel can and do send PRRs to mills that have that capability.

    Response: For combustion at PRRs within the paper recycling industry, the Agency examined the data in the record from previous rulemakings as well as comments received on the proposal. The Agency has determined that it is appropriate to revise the proposed to include PRRs generated by paper recycling mills that are transferred off-site to other paper recycling mills for energy recovery. This determination addresses those generators that do not have the capability to combust the materials on-site, but who wish to transfer their PRRs 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 are utilized in the same manner as self-generated paper recycling residuals i.e., they are legitimately burned for fuel in solid fuel boilers that are designed to burn wet fuels, with mills optimizing their operation around boiler design. Thus, we have determined that such use does not constitute discard.

    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.

    Comment: PRRs are an important part of the fuel mix for facilities other than paper recycling mills, and third party sellers and purchasers classify PRR as fuel. Limiting the ability to utilize PRRs as fuel to those paper mills that have on-site boilers that are designed to burn solid fuel is arbitrary and unnecessary. Many facilities routinely purchase and transport non-hazardous secondary materials generated at a third party location to their sites for legitimate use as fuel. These materials are sourced and purchased as fuels from others and thereby satisfy the first two legitimacy criteria: (1) Be handled as a commodity with an established market; and (2) have sufficient Btu content to support their use as fuel. The third legitimacy criterion (contain contaminants that are not significantly higher in concentration than traditional fuel products), is addressed in the user's air permit rather than in a duplicative non-waste determination process.

    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.

    Response: The Agency disagrees that the categorical non-waste determination should include PRRs combusted at facilities that are not paper recycling mills, and lacks sufficient information to determine that combustors outside the paper recycling industry continue to meet the legitimacy criteria and are, therefore, not discarded.

    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.

    Comment: The EPA should include cement kilns as an appropriate off-site end-user for utilization of PRR categorical non-waste fuels. Cement kilns are capable of handling a wide variety of fuels without the need for extensive processing that some other combustion facilities require in order for the materials to be legitimate. A table comparing the contaminant levels in PRRs to those found in the solid traditional fuels used at cement kilns, including coal and coke was provided.99 The table shows that contaminant concentrations in the PRR categorical non-wastes are less than the range maximum for coal and coke, which are the solid traditional fuels used in cement kilns. Meaningful heating values of 3,700 Btu/lb are also well within the design and operating range of cement kilns. Some kilns inject water for NOX control and the same effect could be achieved using a high moisture fuel material. There is variation in the capabilities and other environmental restrictions of facilities capable of using PRR categorical non-waste fuels, and cement kilns in particular generally have the ability to use a wider variety of fuels. These materials have great value to the energy intensive cement industry, which manages alternative fuels as valuable commodities.

    99 Included in the docket for the final rule.

    Response: The Agency disagrees that the categorical non-waste determination should include PRRs transported offsite and combusted at cement kilns. The information presented on cement kilns lacks sufficient detail overall to determine that such PRRs continue to meet the legitimacy criteria and are not discarded. The information that was received included the referenced table showing that contaminant concentrations in the PRRs combusted in cement kiln are less than the range for solid fuels, as well as cement kilns overall capability to use a wide range of materials with lower heating values that may not be practical in other combustion processes. However, no information was provided, as requested, as to how PRRs are managed as a valuable commodity from the point of generation at the paper recycling mill to insertion at the off-site combustor (i.e., cement kiln) to clearly show that discard is not occurring.

    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 i.e., “transformed” into a non-waste fuel, in accordance with the processing definition at 40 CFR 241.2, and meet legitimacy criteria prior to combustion. The capabilities of the combustion unit are not a factor in determining whether the material has been sufficiently 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.

    b. Definition of PRRs

    Comment: The EPA proposes to define PRRs as follows: “Paper recycling residuals means the co-product material generated from the paper recycling process and is composed primarily of wet strength and short wood fibers that cannot be used to make new paper and paperboard products. The term paper processing residuals also includes fibers from old corrugated container rejects.” Proposed 40 CFR 241.2.

    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.

    Response: The EPA disagrees that the definition of PRR should not distinguish between wet strength and short wood fibers and the non-fiber material contained in OCC rejects (clays, starches, and other filler and coating additives) as well as other non-fiber material (polystyrene foam, polyethylene film, other plastics, waxes and adhesives, dyes and ink). As discussed in section V.B.4. of this preamble, the Agency finds that PRRs that are not composed primarily of wood fibers unsuitable for making paper and contain more than small amounts of certain non-fiber materials would be considered waste fuels and would not be eligible for this categorical listing.

    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 100 rather than co-products, generated from the recycling of paper, paperboard and corrugated containers. Use of the term co-products could infer that PRRs are a product fuel that has undergone processing through the paper recycling manufacturing process. Rather, the paper recycling manufacturing process primarily makes 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 and legitimately burned in solid fuel boilers that are designed to burn wet fuels.

    100 Secondary materials are materials that are 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.

    The revised definition of Paper recycling residuals at 40 CFR 241.2 appears in the regulatory language at the end of this document.

    C. Creosote-Treated Railroad Ties (CTRTs)

    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.

    1. Detailed Description of CTRTs

    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 P2.101 Railroad ties are typically manufactured using the P2 blend that is more viscous than other blends.

    101 AWPA Standard P1/P13 and P2 provide specifications for coal-tar creosote used for preservative treatment of piles, poles and timber for marine, land and freshwater use. The character of the tar used, the method of distillation, and the temperature range in which the creosote fraction is collected all influence the composition of the creosote, and the composition may vary with the requirement of standard specifications. April 2010. Forest Products Laboratory. 2010 Wood Handbook. General Technical Report FPL_GTR-190. Madison, WI.

    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.102

    102 American Forest & Paper Association, American Wood Council—Letter to EPA Administrator, December 6, 2012.

    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; 103 and the combustor as third party energy producers. Typically, ownership of the crossties is transferred directly from the generator to the reclamation company that sorts materials for highest value secondary uses, and then sells the products to end-users, including those combusting the material as fuel. Some reclamation companies sell CTRTs to processors who remove metal contaminants and grind the ties into chipped wood. Other reclamation companies have their own grinders, do their own contaminant removal, and can sell directly to the combusting facilities. Information submitted to the Agency states there are approximately 15 CTRT recovery companies in North America with industry wide revenues of $65-75 million. Members of AF&PA report that the value of CTRTs is underscored by the approximately $20-$30 per ton paid for CTRTs which can sometimes be a premium price compared to certain hog fuels (untreated clean wood residues from sawmills).104

    103 In some cases, the reclamation company sells the crossties to a separate company for processing.

    104 American Forest & Paper Association, American Wood Council—Letter to EPA Administrator, December 6, 2012.

    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.105 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 their value as a landscaping element or fuel could be realized.

    105 M.A. Energy Resources LLC, Petition submitted to Administrator, EPA. February 2013.

    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.106 The combined fuel may be further hammered and screened prior to combustion. 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.

    106 American Forest & Paper Association, American Wood Council—Letter to EPA Administrator, December 6, 2012.

    2. CTRTs Under Previous NHSM Rules a. March 21, 2011 NHSM Final Rule

    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 contaminants at levels that are not comparable to or lower than those found in wood or coal, the fuel that creosote-treated wood would replace. In making the assessment, the Agency did not consider fuel oil 107 as a traditional fuel that CTRTs would replace, and concluded at the time that combustion of creosote-treated wood may result in destruction of contaminants contained in those materials. Such destruction is an indication of incineration, a waste activity. Accordingly, creosote-treated wood, including CTRTs when burned, seemed more like a waste than a commodity, and did not meet the contaminant legitimacy criterion. This material, therefore, was considered a solid waste when burned and units combusting it would be subject to the CAA section 129 emission standards. The conclusions from the March 21, 2011 rule regarding creosote-treated wood are discussed further in section V.C.4. of this preamble.

    107 For the purposes of this final rule, fuel oil means oils 1-6, including distillate, residual, kerosene, diesel, and other petroleum based oils. It does not include gasoline or unrefined crude oil.

    b. February 2013 NHSM Final Rule

    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.

    A list of industry sectors, in addition to forest product mills, that burn railroad ties for energy recovery: One respondent claimed that a number of end-use combustors utilize CTRTs as an alternative fuel to offset fossil fuel at all times. Such facilities use as much as 100-500 tons of CTRTs daily. The respondent also claimed to know of additional end-use combustors that utilize CTRTs occasionally based on availability and cost. Furthermore, the respondent was aware of other end-use combustors that are operationally able to utilize CTRTs as an alternative fuel to offset fossil fuel, but have chosen not to use CTRTs as a result of the current solid-waste implications associated with CTRTs. The end-use combustors that currently utilize CTRTs, both full-time and part-time, represent a variety of industry sectors, including pulp and paper manufacturing, cogeneration plants, utilities, and chemical manufacturing facilities. For the utility sector, at least 14 utilities could burn (i.e., are permitted to burn) or are burning CTRTs.108 Another respondent claimed that data 109 show that a number of forest product mills are currently using railroad ties as a fuel and that other mills are permitted to burn these materials as fuels, but have stopped using them as a fuel due to their uncertain regulatory status, as well as other economic factors (e.g., lower cost of other fuels).

    108 Information received subsequent to the request for data in the February 13, 2013 rule discussed above claims that 14 entities in the utility sector could burn (i.e., are permitted to burn) or are burning cross-tie derived fuel (i.e., CTRTs). Of the 14 entities, 9 companies are currently firing or have fired CTRTs within the past two years. Information on pulp and paper and utility sources currently utilizing CTRTs demonstrates that several of these sources use between 5,000 and 70,000 tons of CTRTs per year. Information compiled by M.A. Energy LLC. (MAER) contained in letters and emails from All4 Inc. to EPA dated January 29, and February 28, 2014.

    109 American Forest and Paper Association and American Wood Council's letter to George Faison, EPA. March 7, 2013.

    The types of boilers (e.g., kilns, stoker boilers, circulating fluidized bed, etc.) that burn railroad ties for energy recovery. Respondents stated that the types of units operated by those end-use combustors that utilize CTRTs as an alternative fuel include fluidized bed, traveling grate, and spreader stoker. Forest product industry boilers that burn railroad ties are generally one of three types: stoker, bubbling bed or fluidized bed boilers.110

    110 Information was received that the forest products industry boilers combusting CTRTs also includes hybrid suspension grate boilers. See docket EPA-HQ-RCRA-2013-0110-0076.

    • The traditional fuels and relative amounts (e.g., startup, 30 percent, 100 percent) of these traditional fuels that could otherwise generally be burned in these types of units. Respondents also claimed that units operated by end-use combustors that utilize CTRTs as an alternative fuel typically burn a variety of “traditional fuels,” such as coal, biomass (i.e., hog fuel, bark fuel, and other biomass fuel materials), and fuel oil, as well as other materials and wastes, such as tire derived fuel, waste derived liquid fuel, and waste derived solid fuel.111 112 In general, they claimed that all of the units that burn CTRTs also burn significant quantities of biomass given the similarity of the fuels' characteristics. In addition, they claimed that most of these units are permitted to burn fuel oil either during start-up or during normal operations. The respondents claimed that many factors determine how much fuel oil is burned. For example, because natural gas prices are low, natural gas is often the fuel of choice, if available. In addition, they claimed that some states are looking to reduce SO2 emissions from sources and thus, encourage greater use of biomass or natural gas rather than fuel oil.113

    111 To the extent that any of these boilers burn fuel derived from waste, or any other solid waste, they would be subject to the CAA section 129 CISWI standards, and the Agency's rule in this document would not impact their regulatory status.

    112 American Forest and Paper Association and American Wood Council's letter to George Faison, EPA. March 7, 2013.

    113 Examples of combustors utilizing a variety of traditional and other fuels, including facilities combusting both CTRTs and fuel oil, is found in documentation provided by the American Associations of Railroads (AAR). The document listed 11 non- pulp and paper facilities including power generators. All of the facilities listed combust CTRTs, three facilities combust CTRT and fuel oil, three facilities combust CTRT and natural gas. Other fuels combusted include tire-derived fuel, and landfill gas. February 2013.

    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.114 However, in the context of a specific non-waste determination under 40 CFR 241.4(a), the respondents argued that the EPA has the opportunity to evaluate all the factors relating to the use of CTRTs as a fuel, including the fact that CTRTs is a commodity that is purchased by the combustor. Furthermore, respondents argued that the EPA has the discretion to recognize that when a combustor purchases CTRTs and then burns it in a boiler, that combustion is for the purpose of generating energy rather than discarding the railroad ties. According to the respondents, any other conclusion would lead to the absurd result that one boiler can burn CTRTs as a legitimate fuel and another boiler—with essentially the same design except for a nozzle feed for fuel oil—would have to consider the CTRTs as a solid waste. (See section V.B.6 of this preamble for the EPA's consideration of the information and views presented by these respondents.)

    114 See 78 FR 9149

    The extent to which non-industrial boilers (e.g., commercial or residential boilers) burn CTRTs for energy recover. The respondent understood that the residential use of CTRTs for purposes of energy recovery is unlikely. However, they explained that several local utilities in the northern Midwest utilize CTRTs for purposes of power generation but they have not identified the specific facilities.

    • 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 (i.e., PAH-16), dibenzofuran, cresols, hexachlorobenzene, 2,4-dinitrotoluene, biphenyl, quinoline, and dioxins.115 Respondents submitted contaminant data for crushed CTRTs, which are discussed in section V.C.4. of this preamble. With the exception of dioxins, which respondents explain will not be present in CTRTs, analyses were submitted for all requested constituents and other contaminants.

    115 The Agency requested these analyses based on the limited information previously available concerning the chemical makeup of CTRTs. That limited information included one well-studied sample from 1990 (showing the presence of both PAHs and dibenzofuran), past TCLP results (which showing the presence of cresols, hexachlorobenzene and 2,4-dinitrotoluene), Material Safety Data Sheets for coal tar creosote (which showing the potential presence of biphenyl and quinoline), and the absence of dioxin analyses prior to combustion despite extensive dioxin analyses of post-combustion emissions.

    3. Scope of the Proposed Rule and Final Categorical Non-Waste Listing for CTRT

    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; 116

    116 Statements at meeting between American Forest and Paper Association and Mathy Stanislaus on December 19, 2013 indicate that, CTRTs generally comprise 40% of total fuel load.

    • 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 (i.e., removing oil delivery equipment) in order to burn natural gas should be considered discard of the CTRTs. EPA considered that these facilities have demonstrated the ability to burn fuel oil along with biomass and should not be penalized for switching to the cleaner natural gas fuel. Information submitted at the time indicating that CTRTs are an important part of the fuel mix due to the consistently lower moisture content and higher Btu value, as well as the benefits of drier, more consistent fuel to combustion units with significant swings in steam demand, further suggested that discard is not occurring.

    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, i.e. levels not comparable to the traditional fuel the unit is currently designed to burn. The particular facilities in this case had used CTRTs and would clearly be in compliance with the legitimacy criteria if they did not switch to the cleaner natural gas fuel. EPA believed it appropriate to balance other relevant factors in this categorical non-waste determination and that it is appropriate for the Agency to decide that the switching to the cleaner natural gas would not render the CTRTs a waste fuel in view of the historical usage as a product fuel in the stoker, bubbling bed and fluidized bed boilers.

    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 (e.g. oil delivery mechanisms are removed) in order to use natural gas instead of fuel oil as part of normal operations and not solely as part of start-up or shut-down operations. The CTRT may continue to be combusted as a product fuel under this section only if certain conditions are met, which are intended to ensure that the CTRTs are not being discarded:

    • The CTRTs must be combusted in existing (i.e. commenced construction prior to April 14, 2014) stoker, bubbling bed, fluidized bed or hybrid suspension grate boilers; and

    • 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.

    4. Rationale for Final Rule

    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.

    a. Discard

    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.

    i. Storage of CTRT

    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.117 The letter further states that there is a robust market for companies engaged in railroad tie reclamation, and the cost of this material indicates that the material is a valuable commodity and has not been discarded.

    117 As discussed in the NHSM final rule (76 FR 15520), “reasonable time frame” is not specifically defined as such time frames vary among the large number of non-hazardous secondary materials and industries involved.

    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 (e.g., landscaping, as a fuel or land filled) shows that the material has been discarded and is a solid waste (see the preamble discussion of discard 76 FR 15463 in the March 21, 2011 rule). The assertion that the CTRTs are a valuable commodity in a robust market does not change the fact that the CTRTs have been discarded at some point. NHSMs may have value in the marketplace and still be wastes.

    ii. Processing of CTRTs

    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 (e.g., sizing or drying of the material, in combination with other operations); chemically improve the as-fired energy content; or improve the ingredient characteristics. Minimal operations that result only in modifying the size of the material by shredding do not constitute processing for the purposes of the definition. Specifically, the Agency concludes that CTRTs meet the definition of processing in 40 CFR 241.3 because:

    • 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.

    b. Legitimacy Criteria

    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 thus discarded, the Agency may consider other relevant factors in determining whether to list CTRT as a categorical non-waste fuel (40 CFR 241.4(b)(5)(ii)). The Agency adopts for the final rule the reasoning explained below.

    i. Managed as a Valuable Commodity

    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.118

    118 Prior to the CTRTs being processed as a product fuel, the CTRTs are considered solid wastes and would be subject to appropriate federal, state, and local requirements.

    ii. Meaningful Heating Value and Used as Fuel To Recover Energy

    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.119 Information compiled by the EPA in 2011 also specifies that CTRTs could replace clean wood that has an average as-fired heating value of 5,150 Btu/lb, with a low as-fired heating value of 3,440 Btu/lb.120 Thus, CTRTs have greater heating value than the traditional fuel it replaces, and meet the criterion for meaningful heating value and used as a fuel to recover energy, and are not discarded for purposes of this criterion.

    119 See 76 FR 15541.

    120 Fuel analysis data for unadulterated wood. USEPA, Office of Air Quality Planning and Standards, Emissions Data for Boilers and Process Heaters Containing Stack Test, CEM & Fuel Analysis Data Reported Under ICR No. 2286.03 (Version 6) EPA Docket Number EPA-HQ-OAR-2002-0058-3255. February 2011.

    iii. Contaminants Comparable to or Lower Than Traditional Fuels

    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.

    Contaminant Comparisons in CTRTs to Fuel Oil and Biomass. Table 3 of this preamble lists the aggregated CTRT data received as it compares to contaminants found in two traditional fuels that industry claim are used, in varying amounts, at facilities burning processed CTRTs for energy recovery.

    Table 3—Contaminant Ranges in Traditional Fuels & CTRT [In parts per million] Contaminant Biomass a Fuel oil a CTRT b Metal Elements Antimony (Sb) ND-26 ND-15.7 ND Arsenic (As) ND-298 ND-13 ND-3.2
  • ND
  • Beryllium (Be) ND-10 ND-19 ND-0.3 Cadmium (Cd) ND-17 ND-1.4 ND-0.3 Chromium (Cr) ND-340 ND-37 ND-15.3 Cobalt (Co) ND-213 ND-8.5 ND Lead (Pb) ND-340 ND-56.8 ND-9.6 Manganese (Mn) ND-15,800 ND-3,200 63-185 Mercury (Hg) ND-1.1 ND-0.2 0.02-0.05 Nickel (Ni) ND-540 ND-270 ND-38 Selenium (Se) ND-9 ND-4 ND-1 Non-Metal Elements Chlorine (Cl) ND-5,400 ND-1,260 22-400 Fluorine (F) ND-300 ND-14 100 Nitrogen (N) 200—39,500 42-8,950 1,600-14,400 Sulfur (S) ND-8,700 ND-57,000 681-3,277 Volatile Organic Compound (VOC) Hazardous Air Pollutants Benzene ND-75 ND Phenol ND-7,700 ND Styrene ND-320 ND Toluene ND-380 ND Xylenes ND-3,100 0.325 Cumene 6,000-8,600 ND Ethyl benzene 22-1270 0.058 Formaldehyde 1.6-27 ND Hexane 50-10,000 ND 15 Additional VOC ND Total VOC c 1.6-27 6,072-19,810 0.383 Semivolatile Hazardous Pollutants Biphenyl 1,000-1,200 137-330 16-PAH d 3,900-54,700 6641-21,053 Dibenzofuran 570-1,500 Quinoline 40.2 Cresols 1.51 Hexachlorobenzene ND ND 2,4-dinitrotoluene ND ND Lindane 0.238 11 Additional SVOC ND Total SVOC c 4,900-54,700 7,618-22,883 a “Contaminant Concentrations in Traditional Fuels: Tables for Comparison” document available at http://www.epa.gov/epawaste/nonhaz/define/pdfs/nhsm_cont_tf.pdf. Contaminant data drawn from various literature sources and from data submitted to USEPA, Office of Air Quality Planning and Standards (OAQPS). b (1) MA Energy Resources, LLC. February 2013 Crosstie Derived Fuel Petition; (2) URS, Evaluation of Used Railroad Ties Treated with Creosote. Prepared for Association of American Railroads. January 28, 2013; (3) AF&PA, Comparison of Contaminant Concentrations in Crosstie Derived Fuel with Traditional Fuels. February 28, 2013. c Total VOC and SVOC ranges do not represent a simple sum of the minimum and maximum values for each contaminant. This is because minimum and maximum concentrations for individual VOCs and SVOCs do not always come from the same sample. d 16-PAH includes: Acenaphthene, acenaphthylene, anthracene, benz(a)anthracene, benzo(a)pyrene, benzo(b)fluoranthene, benzo(g,h,i)perylene, benzo(k)fluoranthene, chrysene, dibenz(a,h)anthracene, fluoranthene, fluorene, indeno(1,2,3-cd)pyrene, naphthalene, phenanthrene, and pyrene. 16-PAH is designated as Total PAH in the Table for Comparison cited in note “a” above.

    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.121 These compounds are largely nonexistent in clean wood and biomass, and the contaminants are therefore not comparable in this instance. In fact, they are present at orders of magnitude higher than found in clean wood and biomass.

    121 We note that for several SVOCs—cresols, hexachlorobenzene, and 2,4-dinitrotoluene, which were expected to be in creosote, and for which information was specifically requested in the February 7, 2013 NHSM final rule (78 FR 9111), the data demonstrate that they were not detectable, or were present at levels so low to be considered comparable.

    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.122

    122 As discussed previously, the March 21, 2011 NHSM final rule (76 FR 15456), noting the presence of hexachlorobenzene and dinitrotoluene, suggested that creosote-treated lumber include contaminants at levels that are not comparable to those found in wood or coal, the fuel that creosote-treated wood would replace, and would thus be considered solid wastes. This final rule differs in several respects from the conclusions in the March 2011 rule. This final rule concludes that CTRTs are a categorical non-waste when combusted in units designed to burn both fuel oil and biomass. The March 2011 rule, using 1990 data on railroad cross ties, was based on contaminant comparisons to coal and biomass and not fuel oil. As discussed above, when compared to fuel oil, total SVOC contaminant concentrations (which would include dinitrotoluene and hexachlorobenzene) in CTRTs would be less that those found in fuel oil, and in fact, the 2012 data referenced in this final rule showed non-detects for those two contaminants.

    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) 123 Accordingly, the ability to burn a fuel in a combustion unit does have a basic set of requirements, the most basic of which is the ability to feed the material into the combustion unit. The unit should also be able to ensure the material is well-mixed and maintain temperatures within unit specifications.

    123 78 FR 9149 states “If a NHSM does not contain contaminants at levels comparable to or lower than those found in any [emphasis added] traditional fuel that a combustion unit could burn, then it follows that discard could be occurring if the NHSM were combusted. Whether contaminants in these cases would be destroyed or discarded through releases to the air, they could not be considered a normal part of a legitimate fuel and the NHSM would be considered a solid waste when used as a fuel in that combustion unit.”

    Available information regarding use of fuel oil. As discussed in section V.C.2. of this preamble, industry stated during the comment period that there are combustion units designed to burn biomass and fuel oil, but did not identify specific units. A March 2013 letter from AF&PA 124 stated that the overwhelming majority of CTRTs burned at paper mills are burned in boilers that are fully capable and permitted to burn at maximum capacity rating. Most of these boilers (80 percent) can or do burn oil during operating conditions outside of startup and shutdown periods.125 Industry also stated that units operated by end-use combustors that utilize CTRTs as an alternative fuel typically burn a variety of “traditional fuels,” such as coal, biomass (i.e., hog fuel, bark fuel, and other biomass fuel materials), and fuel oil, as well as other materials. They stated that all of the units that burn CTRTs also burn significant quantities of biomass given the similarity of the fuels' characteristics. In addition, most of these units are permitted to burn fuel oil either during start-up or during normal operations. The EPA finds, based on this information, units do combust multiple fuel including fuel oil and CTRTs.126

    124 American Forest and Paper Association and American Wood Council's letter to George Faison, EPA. March 7, 2013. EPA-HQ-RCRA-2013-0110-003.

    125 American Forest and Paper Association and American Wood Council's letter to George Faison, EPA. March 7, 2013. EPA-HQ_RCRA-2013-0110-003.

    126 The Agency notes that in 2008, information was collected from owners and operators of combustion units across a wide variety of industries, including use of fuel oil, in its development of emissions standards for boilers and process heaters under section 112 of the Clean Air Act. In that context, based on the information submitted by industry at the time (including petitioners and others), EPA concluded that units that combust solid fuels generally used fuel oil or natural gas only as a startup fuel and that changing the fuel type in such units would generally require extensive changes to the fuel handling and feeding system, as well as modification to the burners and combustion chambers. 75 FR 32006, 32017. The information submitted for the ICR, however, also stated that some biomass units may combust fuel oil at other times, for example, for transient flame stability purposes if they are combusting biomass with a high moisture content. The ICR did not state the amount of fuel oil being combusted, or whether fuel oil was combusted alone or in conjunction with solid fuel, such as biomass. Although recent information outlined above shows that units do combust multiple fuels including CTRTs and fuel oil, at the time of the development of the boiler MACT, EPA did not have information, including information submitted in response to the ICR, indicating there are units designed to burn solid fuel which commonly switch between combusting biomass and fuel oil or otherwise combusted fuel oil as part of normal operation.

    Contaminant Comparisons to Coal. Data received from industry' included information that boilers combusting CTRTs may also combust coal, which is a traditional fuel. 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.127 In this scenario, as shown in Table 4 of this preamble, maximum levels of SVOCs in CTRTs (22,883 ppm) exceeded those in coal (2,343 ppm) and biomass (SVOC levels largely non-existent). Thus, units that are designed to burn only coal and biomass would not meet the legitimacy criterion for contaminant comparison to CTRTs, an indication that discard may be occurring.

    127 Contaminant levels in coal presented in “Contaminant Concentrations in Traditional Fuels: Tables for Comparison” document available at http://www.epa.gov/epawaste/nonhaz/define/pdfs/nhsm_cont_tf.pdf. Contaminant data drawn from various literature sources and from data submitted to USEPA, Office of Air Quality Planning and Standards (OAQPS).

    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).

    Table 4—Contaminant Ranges in Biomass, Fuel Oil, Coal & CTRT [In parts per million] Contaminant Biomass a Fuel oil a CTRT b Coal Metal Elements Antimony (Sb) ND-26 ND-15.7 ND 0.5—10 Arsenic (As) ND-298 ND-13 ND-3.2 ND 0.5-174 Beryllium (Be) ND-10 ND-19 ND-0.3 0.1-206 Cadmium (Cd) ND-17 ND-1.4 ND-0.3 0.1-19 Chromium (Cr) ND-340 ND-37 ND-15.3 0.5-168 Cobalt (Co) ND-213 ND-8.5 ND 0.5-30 Lead (Pb) ND-340 ND-56.8 ND-9.6 2-148 Manganese (Mn) ND-15,800 ND-3,200 63—185 5-512 Mercury (Hg) ND-1.1 ND-0.2 0.02-0.05 0.02-31 Nickel (Ni) ND-540 ND-270 ND-38 0.5-730 Selenium (Se) ND-9 ND-4 ND-1 0.2-743 Non-Metal Elements Chlorine (Cl) ND-5,400 ND-1,260 22-400 ND-9,080 Fluorine (F) ND-300 ND-14 100 ND-178 Nitrogen (N) 200-39,500 42-8,950 1,600-14,400 13,600-54,000 Sulfur (S) ND-8,700 ND-57,000 681-3,277 740-61,300 Volatile Organic Compound (VOC) Hazardous Air Pollutants Benzene ND-75 ND ND-38 Phenol ND-7,700 ND Styrene ND-320 ND 1.0-26 Toluene ND-380 ND 8.6-56 Xylenes ND-3,100 0.325 4.0-28 Cumene 6,000-8,600 ND Ethyl benzene 22-1,270 0.058 0.7-5.4 Formaldehyde 1.6-27 ND Hexane 50-10,000 ND 15 Additional VOC ND Total VOCc 1.6-27 6,072-19,810 0.383 14.3-125.4 Semivolatile Organic Compound (VOC) Hazardous Air Pollutants Biphenyl 1,000-1,200 137-330 16-PAH d 3,900-54,700 6641-21,053 6-253 Dibenzofuran 570-1,500 Quinoline 40.2 Cresols 1.51 Hexachlorobenzene ND ND 2,4-dinitrotoluene ND ND Lindane 0.238 11 Additional SVOC ND PAH (52 extractable) 14-2,090 Total SVOCc 4,900-54,700 7,618-22,883 20-2,343 a “Contaminant Concentrations in Traditional Fuels: Tables for Comparison” document available at http://www.epa.gov/epawaste/nonhaz/define/pdfs/nhsm_cont_tf.pdf. Contaminant data drawn from various literature sources and from data submitted to USEPA, Office of Air Quality Planning and Standards (OAQPS). b (1) MA Energy Resources, LLC. February 2013 Crosstie Derived Fuel Petition; (2) URS, Evaluation of Used Railroad Ties Treated with Creosote. Prepared for Association of American Railroads. January 28, 2013; (3) AF&PA, Comparison of Contaminant Concentrations in Crosstie Derived Fuel with Traditional Fuels. February 28, 2013. c Total VOC and SVOC ranges do not represent a simple sum of the minimum and maximum values for each contaminant. This is because minimum and maximum concentrations for individual VOCs and SVOCs do not always come from the same sample. d 16-PAH includes: Acenaphthene, acenaphthylene, anthracene, benz(a)anthracene, benzo(a)pyrene, benzo(b)fluoranthene, benzo(g,h,i)perylene, benzo(k)fluoranthene, chrysene, dibenz(a,h)anthracene, fluoranthene, fluorene, indeno(1,2,3-cd)pyrene, naphthalene, phenanthrene, and pyrene. 16-PAH is designated as Total PAH in the Table for Comparison cited in note “a” above.

    Contaminant Information related to dibenzofurans and dioxins. As discussed above, the Agency requested data on dibenzofuran and dioxins, in large part because dibenzofuran is known to be present in CTRTs and listed as a HAP under CAA section 112 and dioxins are a pollutant under CAA sections 112 and 129.

    Industry submitted an explanatory document in response to the Agency's request.128 The document provided additional information regarding (a) the presence of dibenzofuran in creosote and creosote-treated wood, and (b) whether the presence of dibenzofuran is associated with the concurrent presence of the polychlorinated versions of these compounds, viz., polychlorinated dibenzo p-dioxins and dibenzofurans (PCDD/F—often collectively termed dioxins).

    128 American Forest and Paper Association and American Wood Council—Letter to George Faison, EPA March 7, 2013. EPA-HQ-RCRA-0110-003.

    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.129 Regarding dioxins, the document shows that dioxins will not be present in the material. The Agency agrees that the level of chlorine during creosote production is not sufficient to form dioxins in coal tar creosote and therefore dioxin will not be present in CTRTs prior to combustion.

    129 When making contaminant comparisons for purposes of meeting the legitimacy criterion, it would be appropriate in this circumstance to find that grouping of contaminants would not result in discard. For example, under the grouping concept, individual SVOC levels may be elevated above that of the traditional fuel, but the contaminant legitimacy criterion will be met as long as total SVOCs is comparable to or less than that of the traditional fuel. Such an approach is standard practice employed by the Agency in developing regulations and is consistent with monitoring standards under CAA sections 112 and 129. See 78 FR 9146, February 7, 2013, for further findings that relate to the issue of grouping contaminants for purposes of determining discard.

    c. Other Relevant Factors in a Categorical Non-Waste Determination for CTRTs

    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.130 131

    130 Petitioner arguments regarding functional equivalence and use of CTRTs as a commodity are also outlined in Legal Analysis Supporting Listing Railroad Tie Fuel as a Nonwaste under 40 CFR 241.4(a)(January 15, 2014.) American Forest and Paper Association. Docket number EPA-HQ-RCRA-201-0110-0008.

    131 To further support a finding of functional equivalency, petitioners submitted data claiming that stack emissions of PAHs (PAHs are higher in railroad ties than in coal or biomass), are controlled in the same way as all organic constituents present in the other fuels used by the boilers that combust railroad tie fuel. The Air Emissions Impact of Burning Railroad Tie-Derived Fuel. NCASI, January 2014.

    • 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.132 As discussed previously, units will be switching from fuel oil to natural gas. Such units designed to combust both fuel oil and CTRTs include stoker, bubbling bed and fluidized bed boilers. Boilers that have burned fuel oil currently or in the past will discontinue using fuel oil, however, industry argues that they have clearly demonstrated the ability to burn that material as a product fuel.

    132 Petitioners also argued in their December 19, 2013 background material that high PAH levels in fuels are not related to PAH emission levels. They state that Boiler MACT carbon monoxide (CO) limits ensure good combustion practices by minimizing PAHs and other products of incomplete combustion (under the Boiler MACT standards, CO is a surrogate for organic HAPs such as PAHs). Dry fuels such as CTRTs increase heat value of the fuel mix improving combustion temperature and conditions.

    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 traditional fuels since it must be processed by reclamation companies to remove metals (spikes, nails etc.) and shredded into chips to make it suitable as a fuel source.

    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 133 paper mills are currently designed to combust both fuel oil and CTRTs, few, if any, of these units may be combusting both fuel oil and biomass in the future since those units will be switching from fuel oil to natural gas for start-up periods and operations. The industry stated that continued use of fuel oil during operation would result in higher compliance costs and higher costs per Btu. Industry stated that the switch to natural gas for operation requires replacement of start-up fuel systems, and that the most efficient and least emitting start-up systems use specialized burners for gas.

    133 Section 112(a)(1) of the CAA defines the term “major source” to mean any stationary source or group of stationary sources located within a contiguous area that emit or have the potential to emit in the aggregate, 10 tons per year or more of any hazardous air pollutant or 25 tons per year or more of any combination of hazardous air pollutants.

    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 134 would not render the CTRT a waste fuel. The facilities have demonstrated the ability to burn fuel oil and biomass and should not be penalized for switching to a cleaner fuel. The CTRTs do not become wastes solely because of the switch to natural gas. Information indicating that CTRTs are an important part of the fuel mix for these units due to the consistently lower moisture content and higher Btu value as well as the benefits of drier more consistent fuel to combustion units with significant swings in steam demand further show that discard is not occurring.

    134 The Agency recognizes natural gas as a source of clean energy. The burning of natural gas produces nitrogen oxides and carbon dioxide, but in lower quantities than burning coal or oil. Methane, a primary component of natural gas and a greenhouse gas, can also be emitted into the air when natural gas is not burned completely. Similarly, methane can be emitted as the result of leaks and losses during transportation. Emissions of sulfur dioxide and mercury compounds from burning natural gas are negligible. (See http://www.epa.gov/cleanenergy/energy-and-you/affect/natural-gas.html.)

    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 (e.g., oil delivery mechanisms are removed) in order to use natural gas instead of fuel oil as part of normal operations and not solely as part of start-up or shut-down operations. The CTRT may continue to be combusted as a product fuel only if certain conditions are met, which are intended to ensure that the CTRTs are not being discarded:

    • CTRTs must be combusted in existing (i.e., commenced construction prior to April 14, 2014) stoker, bubbling bed, fluidized bed or hybrid suspension grate boilers; and

    • 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, i.e., levels not comparable to the traditional fuel the unit is currently designed to burn. The particular facilities in this case had used CTRTs and would clearly be in compliance with the legitimacy criteria if they did not switch to the cleaner natural gas fuel. EPA determined that it is appropriate to balance other relevant factors in this categorical non-waste determination and that it is appropriate for the Agency to decide that the switching to the cleaner natural gas would not render the CTRTs a waste fuel in view of historical usage as a product fuel in stoker, bubbling bed, fluidized bed and hybrid suspension grate boilers.

    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 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 for 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 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.

    5. Summary of Comments Requested

    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):

    Use of Multiple Fuels. The Agency requested comments specifically on the use of multiple fuels for contaminant comparison in evaluating whether to categorically list CTRTs, including whether fuel oil itself should be one of the traditional fuels used for comparison given, and any additional data that should be considered in making the comparability determination.

    Additional Approach. Regarding the additional approach under consideration, the Agency requested comment on the approach and the following conditions: whether the approach should be applied to sources at other industries in addition to pulp and paper mills (e.g., utilities and co-generation plants); the appropriateness of the 40 percent limit as a percentage of fuel used including the monthly or yearly basis for the limit; if the additional approach is applied to other industries, such as utilities, what percentage (if any) would be appropriate for that industry(s); and whether the approach should be subject to recordkeeping requirements.

    6. Responses to Comments a. Specific Requests for Comment i. Use of Multiple Fuels

    Comment: Regarding the use of multiple fuels for contaminant comparison in evaluating whether to categorically list CTRTs, combustion units are often designed to burn multiple traditional fuels, some relying on different fuel types at different times based on availability of fuel supplies, market conditions, power demands, and other factors. It would be arbitrary to restrict NHSM combustion for energy recovery, based on contaminant comparison to only one traditional fuel, if that unit could burn a second traditional fuel.

    Response: 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 would be 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. The Agency agrees with the commenter and is retaining the regulatory standard that CTRTs are categorical non-wastes when combusted in units designed to burn both fuel oil and biomass.

    ii. Additional Approach

    Comment: As the EPA stated regarding the additional approach under consideration, fuel switching from oil to natural gas is not evidence of any motivation to discard CTRTs and should not affect the classification of CTRTs as non-solid waste for combustion purposes. The modification has nothing to do with the properties of CTRTs or the burning of CTRTs for energy recovery, but is due to unrelated market conditions for fuel oil and natural gas. The listing should not be limited to only units “that are currently designed to burn both biomass and fuel oil but are changing (i.e., removing oil delivery equipment) in order to burn natural gas.” There is no rational basis for this limitation on unit type and it is unclear why the EPA limits this proposed “expansion.”

    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.

    Response: The Agency has determined that the additional approach must be limited to units that are currently designed to burn both biomass and fuel oil but are modified (e.g., removed oil delivery mechanisms) in order to burn natural gas as part of normal operations and not solely as part of start-up or shut-down operations. As discussed above, the particular facilities in this case have used CTRTs and would clearly be in compliance with the legitimacy criteria if they did not switch to the cleaner natural gas fuel. It is appropriate to balance other relevant factors in this categorical non-waste determination and it is appropriate for the Agency to decide that the switching to the cleaner natural gas would not render the CTRTs a waste fuel in view of the historical usage as a product fuel in the stoker, bubbling bed, and fluidized bed boilers. The nature of the CTRTs as a product fuel does not make it a waste on switching to the cleaner natural gas for the boiler.

    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, i.e., levels not comparable to the traditional fuel the unit is currently designed to burn.

    Based on information from industry that in addition to stoker, bubbling bed and fluidized bed boilers, hybrid suspension grate (HSG) boilers also combust CTRT,135 the Agency is extending the additional approach to CTRT combusted in HSG boilers. The Agency notes, however, that use of that boiler type for combustion of CTRT as the primary fuel may be limited. Review of HSG boilers in the Boiler MACT Database (ICR No. 2286.01) (Version 4), indicates that all of the boilers in the HSG subcategory fire bagasse fuels as the primary fuel, and none report routine firing of other types of biomass fuels or CTRTs. When the EPA finalized the HSG subcategory (76 FR 15634, March 21, 2011) the rationale for adding the subcategory was that for combustion-related pollutants (used as a surrogate for organic HAP emissions), the design differences for such hybrid suspension grate boilers are significant, and combustion conditions in these types of units are not similar to those in dutch ovens or true suspension burners that combust fine, dry fuels. The rationale was provided solely in the context of hybrid suspension/grate boilers designed to combust very wet biomass fuels such as bagasse. Bagasse fuels have a moisture content ranging between 40 and over 60 percent moisture content. By contrast, CTRTs have a moisture content of 20 percent on average.136

    135 See EPA-HQ-RCRA-2013-0110-0076 in the docket for this final rule.

    136http://www.rta.org/assets/docs/RTASponsoredResearch/Environmental/creosote%20tie%20evaluation%20article%20_4_.pdf.

    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.

    Comment: The EPA's proposed approach should not include conditions specifying a CTRT fuel use limit of 40 percent on a monthly basis for the clean fuel modified unit listing (i.e., CTRTs combusted in units at major source pulp and paper mills that are being modified in order to use clean fuel such as natural gas, instead of fuel oil). There is no rational basis for this limitation, since a percentage cap has nothing to do with whether or not a material is discarded, and the EPA did not demonstrate that this limit would provide any greater environmental protection. In addition, the EPA should not limit the clean fuel modified unit category to units located only at major source pulp and paper mills. There is no reason why this should be an industry-specific provision. A number of biomass boilers in both the forest products and biomass power industries rely on CTRT fuel, and the EPA has information in the record showing that a variety of other industry sectors currently combust railroad ties, including utilities and chemical manufacturing facilities.

    Response: The Agency is adopting the conditions under the additional approach intended to ensure that the CTRTs are not being discarded, including the condition that CTRTs can comprise no more than 40 percent of the fuel used on an annual heat input basis. While this commenter disagreed on the proposed 40 percent limit on use of CTRTs in units that were once designed to burn fuel oil but do not any longer, we note that other commenters expressed support for this approach.137 As discussed in footnote 114, statements from the pulp and paper industry indicate that CTRTs generally comprise 40% of the total fuel load. EPA also reviewed information from the Boiler MACT database as well as similar information obtained for CISWI units, and noted that the reported annual heat input rates for CTRTs for units that reported firing this material did not exceed 13 percent. Considering that CTRTs have elevated contaminants compared to biomass and natural gas, allowing a fuel usage percentage greater than industry has typically used previously could be indicative of discard. Therefore, the Agency is maintaining the 40 percent usage limitation as a reasonable condition for the categorical non-waste determination for CTRTs in units that have been modified to burn biomass and natural gas instead of biomass and fuel oil.

    137 See docket comment EPA-HQ-RCRA-2013-0110-0082.

    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.138

    138 40 CFR 241.2 defines power producer as a boiler unit producing electricity for sale to the grid. The term does not include units meeting the definition of electricity generating unit under 40 CFR 63.10042 of the Utility Mercury and Air Toxics Standards rule.

    Comment: With regard to whether combustors should be required to keep records that the conditions for burning of CTRTs described above have been met, and the additional recordkeeping requirements to show that the conditions in the additional approach are met, are unnecessary. Any potential issues should already be adequately addressed by the recordkeeping provisions already in place in applicable Boiler MACT and NSPS requirements, state and local regulatory requirements, and facility permits. Further, the existence of a record does not demonstrate whether or not discard is occurring under RCRA. The EPA should continue to rely on the record-keeping requirements under the Clean Air Act rules.

    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.

    Response: The Agency has concluded that additional specific recordkeeping requirements are not required to determine compliance with the additional approach. Current recordkeeping requirements for boilers under 40 CFR 63.7555 require documentation that the material is listed as a categorical non-waste under § 241.4(a) of this chapter, which would include records demonstrating adherence to any conditions applied to the categorical non-waste determination, such as the 40 percent annual heat input limitation.

    b. Additional Comments

    Comment: The EPA should expand this additional approach to allow the combustion of CTRTs in biomass boilers, and specifically, biomass boilers that have already or in the future will convert from coal to biomass. The conversion of a unit from coal to biomass reduces the steam generation capacity compared to the original design. A portion of a higher Btu fuel (such as CTRTs) is incorporated into the mix to make the conversion successful.

    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.

    Response: The Agency recognizes the importance of CTRTs as a fuel to the biomass power industry and to boilers designed specifically for the use of biomass as a fuel. Indeed, there may be environmental benefits to allowing CTRT use. The statutory requirement under RCRA, however, is to determine whether the material is a waste when burned as a fuel. The environmental and efficiency benefits, moreover, would accrue if the facilities were burning under CAA 112 or 129. Thus, most of the policy arguments propounded by the comment may be valid but not necessarily relevant to whether material is discarded.

    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.

    Comment: The EPA's proposal included the combustion of CTRTs as a non-waste fuel, and stressed that these materials are a valuable commodity and a legitimate alternative fuel. However, combustion of CTRTs should not be limited to only units “designed to burn biomass and fuel oil.” Such limitations may be necessary when evaluating case-by-case NHSMs against the legitimacy criteria, but, they are not appropriate for the categorical listing of a non-waste fuel. For example, in listing TDF (tire-derived fuel) as a categorical non‐waste fuel, the EPA compared the contaminants in scrap tires to the contaminants in coal, which was considered the traditional fuel that TDF typically replaces, to satisfy the third legitimacy criterion. However, it is important to note that no “designed to burn” conditions are included in the categorical non‐waste listing for TDF. TDF are NHSMs that are categorically not solid waste when used as fuel in a combustion unit. Therefore, the specification of “designed to burn” conditions associated with the proposed non‐waste fuel listing for CTRTs is inconsistent with previous rulemakings and non‐waste fuel determinations.

    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).

    Response: The Agency disagrees that designed to burn conditions or limitations are inappropriate for categorical non-waste determinations. Further, the commenter's argument as to why the “designed to burn” condition should not put limitations on the use of the NHSM as non‐waste fuel is unclear. The purpose of the designed to burn condition is to ensure a facility is not combusting CTRTs as a means of discard. Discard would be occurring if the unit is not designed to burn CTRTs with elevated levels of PAHs. As discussed in section V.C.4. of this preamble, to meet legitimacy criteria and ensure discard is not occurring, any categorical non-waste (as well as materials determined to be non-waste on a case-by-case basis) must contain contaminants or groups of contaminants at levels comparable in concentration to or lower than those in the traditional fuel(s) which the combustion unit is designed to burn (40 CFR 241.3(d)(1)(iii), 40 CFR 241.4(b)). If a facility compared contaminants to a traditional fuel that the unit is not designed to burn, and the fuel is highly contaminated, combustion of that fuel would be considered discard.

    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.139 140 The Agency did not receive information on contaminant comparisons to other traditional fuels besides coal. It is not necessary for the EPA to repeat the importance of the legitimacy criteria in every provision in its regulations.

    139 See 78 FR 9154.

    140 See 76 FR 15494.

    Comment: Seven boilers at a facility are built and designed as biomass boilers, and use fossil fuels for startup and flame stabilization. However, only three of the boilers are permitted and equipped to burn fuel oil, and the remaining units are permitted and equipped to use natural gas. The categorical listing of CTRTs as a non-waste fuel in units designed to burn fuel oil would only allow listing CTRTs as a fuel for one of its facilities (three boilers), while being a waste in the others, despite each of the units being designed to burn primarily solid fuels such as CTRT.

    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.

    Response: The Agency does not agree that CTRTs should be allowed to be used as a fuel in units designed to burn only biomass. In order to legitimately combust CTRTs, the unit must be designed to burn both biomass and fuel oil. As stated in section V.C.4.b.iii., of this preamble, 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 PAHs and, to a lesser extent, the levels of dibenzofuran and biphenyl.141 These compounds are largely nonexistent in clean wood and biomass, and the contaminants are therefore not comparable in this instance. In fact, they are present at orders of magnitude higher than found in clean wood and biomass. Thus, if a unit combusts CTRTs and the unit is designed to burn only biomass, the unit would be able to burn excessive levels of contaminants, which would be waste components. This would constitute discard.

    141 We note that for several SVOCs—cresols, hexachlorobenzene, and 2,4-dinitrotoluene, which were expected to be in creosote, and for which information was specifically requested in the February 7, 2013 NHSM final rule (78 FR 9111), the data demonstrate that they were not detectable, or were present at levels so low to be considered comparable.

    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.

    Comment: The EPA has stated that “information indicating that CTRTs are an important part of the fuel mix due to the consistently lower moisture content and higher Btu value, as well as the benefits of drier more consistent fuel to combustion units with significant swings in steam demand, further suggest that discard is not occurring” (79 FR 21028). This statement supports the determination that CTRTs are functionally equivalent to traditional fuels they replace.

    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.

    Response: In the first instance, the EPA must correct the comment's statement that materials are either fuels or wastes. The very basis of the EPA's NHSM rule is that we need to determine whether materials burned as fuels are wastes or products. The fact that the Agency agrees that material is a good fuel does not mean it is a product fuel. All legitimacy criteria must be met.

    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 comparable traditional fuels. Unlike traditional fuels, CTRTs must be processed by reclamation companies to remove metals (spikes, nails etc.) and shredded into chips to make it suitable as a new fuel product.

    Comment: Cement kilns can utilize a wide variety of fuels and should be included as an acceptable fuel end-user for CTRT non-waste fuels. If the EPA retains the “designed-to-burn” condition, the EPA should state that a source that burns coal and fuel oil, such as cement kilns, also qualifies for the use of CTRTs as a categorically exempt non-waste NHSM. Currently, a source with a combustion unit that predominantly burns coal and fuel oil has to infer that the categorical non-waste NHSM exemption for CTRTs applies based on Footnote 96 (79 FR 21025, April 14, 2014). More clarity would be present if the exemption specifically referenced coal, coke, biomass, and fuel oil fired combustion units.

    Response: The Agency notes first that the comment is in error by characterizing the listing of CTRTs as a categorically “exempt” non-waste. Such determinations are not exempting those materials from the solid waste definition under the RCRA. The part 241 standards overall determine whether materials are solid wastes under the RCRA and must be combusted in units meeting CAA 129 standards, or not solid wastes under the RCRA, and can be combusted in units meeting CAA 112 standards. This rule determines whether or not materials are categorical non-wastes. At no point is the EPA “exempting” or “excluding” material from the solid waste definition.

    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.142 In this scenario, maximum levels of SVOCs in CTRTs (22,883 ppm) exceeded those in coal (2,343 ppm) and biomass (SVOC levels largely non-existent). Thus, units that are designed to burn only coal and biomass would not meet the legitimacy criterion for contaminant comparison to CTRTs. This shows that discard is occurring.

    142 Contaminant levels in coal presented in “Contaminant Concentrations in Traditional Fuels: Tables for Comparison” document available at http://www.epa.gov/epawaste/nonhaz/define/pdfs/nhsm_cont_tf.pdf. Contaminant data drawn from various literature sources and from data submitted to USEPA, Office of Air Quality Planning and Standards (OAQPS).

    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.143

    143 As discussed previously, the March 21, 2011 NHSM final rule (76 FR 15456), noting the presence of hexachlorobenzene and dinitrotoluene, suggested that creosote-treated lumber include contaminants at levels that are not comparable to those found in wood or coal, the fuel that creosote-treated wood would replace, and would thus be considered solid wastes. This final rule differs in several respects from the conclusions in the March 21, 2011 rule. This final rule concludes that CTRTs are a categorical non-waste when combusted in units designed to burn both fuel oil and biomass. The March 21, 2011 rule, using 1990 data on railroad cross ties, was based on contaminant comparisons to coal and biomass and not fuel oil. As discussed above, when compared to fuel oil, total SVOC contaminant concentrations (which would include dinitrotoluene and hexachlorobenzene) in CTRTs would be less that those found in fuel oil, and in fact, the 2012 data referenced in this final rule showed non-detects for those two contaminants.

    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 (e.g., oil delivery equipment removed) in order to use natural gas instead of fuel oil. The CTRT may continue to be combusted as a product fuel only if certain conditions were met, described above, which are all intended to ensure that the CTRTs are not being discarded.

    Comment: Start-up and shut down operating scenarios are sufficient to demonstrate a source's ability to meet a designed to burn criteria for fuel oil. Not including those scenarios is not supported by previous U.S. EPA policy nor by the language in 40 CFR 241.3(d)(1)(iii), which includes the phrase “. . . may choose a traditional fuel that can be or is burned in the particular type of combustion unit . . .”

    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.”

    Response: The Agency disagrees that start-up and shut-down of sources is considered normal operations for the purposes of determining whether a unit is designed to burn a traditional fuel used for contaminant comparison. With regard to meeting the design to burn criteria, the Agency considers normal operations to be a unit that contains burners capable of firing fuel oil as the primary fuel during periods of steady state operations or periods where the fired oil is used as a supplemental fuel to maintain consistent heat input during steady state operations. Specific regulatory language is added in this final rule to clarify that the listing applies only to units designed to burn both biomass and fuel oil as part of normal operations and not just start-up and shut-down operations, as well as units at major source pulp and paper mills or power producers that were modified (e.g., oil delivery mechanisms were removed) in order to use natural gas as part of normal operations and not just start-up and shut down operations (see section 241.4(a)(7)).

    Comment: The EPA should expand the definition of CTRTs to include ties dual treated with creosote and borate. As proposed, the definition is limited to railway support ties treated with a wood preservative containing creosols and phenols and made from coal tar oil. CTRTs may also be treated with a combination of borate and creosote. Use of borate-based compounds has recently become prevalent for the protection of railroad crossties. Use of borate allows for treatment of the inner layers of wood (or heartwood), while creosote typically only treats sapwood. Encapsulating the borate-treated crosstie with creosote adds a hydrophobic outer layer of protection and a barrier that repels white-rot fungi. Borate treatment also reduces the amount of creosote that needs to be used in crossties.

    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,144 demonstrate that wood dual treated with both borate and creosote has lower PAH levels (and lower metals levels) than wood that is treated with creosote alone. Furthermore, the combination of creosote and borate is not expected to yield unwanted synergistic chemical reactions, based on one example of a patented process that treats wood simultaneously using a blended solution of creosote and borate.

    144 Included in the docket for this final rule.

    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.

    Response: The EPA disagrees that the definition of CTRTs should be expanded to include dual treated creosote and borate ties (dual-treated ties) based on the data received. Unlike CTRTs, the December 2013 data for dual-treated ties cited above was limited to a single data point.145 A single data point does not provide enough information that the data analyzed are truly representative of the category of material under consideration, and the legitimacy criterion for contaminants comparable to or less than the traditional fuel the unit is designed to burn has been met. Thus, no determination can be made whether or not the material has been discarded, and is a waste or non-waste. As the record indicates in previous categorical determinations, including CTRTs, multiple unique analytical data points were considered in making categorical determinations.

    145 See also discussion under Comments and Information Received on Other Types of Treated Wood section V.A.6.c.

    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.

    Comment: The EPA does not indicate in the proposal how CTRTs are to be processed to qualify as a non-waste fuel. The EPA has also not included in the proposal any requirements that processing of CTRTs must be conducted using best management practices. The EPA should include in the final rule requirements for processing of CTRTs that include specific criteria for best management practices.

    Response: The Agency agrees the rule should include language identifying how CTRTs are to be processed to qualify as a non-waste fuel. The language in the proposed rule stated the following was a categorical non-waste under 40 CFR 241.4 “Creosote-treated railroad ties that are processed (emphasis added) and combusted in units designed to burn both biomass and fuel oil.”

    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.

    Comment: The EPA bases its treatment of CTRTs as fuel on an incorrect, arbitrary conclusion, reflected in this preamble statement: “CTRTs removed from service and 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 (e.g., landscaping, as a fuel or land filled) indicates that the material has been discarded and is a solid waste.” This statement reflects a complete misunderstanding of how CTRTs are processed and treated in the marketplace. Often times, CTRTs are transported a significant distance to the end user of the ties and therefore, those ties may need to be stored long enough to provide a shipment at a cost-effective freight rate. The availability of CTRTs may not always match the demand for CTRTs. Significant deconstruction of a railway could occur at a time when the marketplace for CTRTs as a fuel is flooded. Thus, storage of CTRTs is reasonable and by no means indicates that CTRTs are discarded.

    Response: The EPA disagrees that lack of cost-effective freight rates and variability in demand would result in a determination that CTRTs are not discarded. Such factors show that the value of ties as a commodity in the marketplace is predicated in part on these variables. The material would, in such cases, be speculatively accumulated with no clear market value. The fact that they may at some point in the future have value as a commodity does not render them non-wastes. Thus, the Agency sees no reason to reconsider its conclusion 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 shows that the material has been discarded and is a solid waste.

    c. Comments and Information Received on Other Types of Treated Railroad Ties

    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,146 TWC requested that the Agency move forward quickly on a subset of materials that were identified in the original April 2013 petition which are creosote borate, copper naphtenate, and copper naphtenate-borate treated railroad ties. In the letter, TWC indicated that these types of ties are increasingly being used as alternatives to creosote treated ties, and that the ability to reuse the ties is an important consideration in rail tie purchasing decisions. The letter stated that TWC will discuss the remaining treated wood materials with EPA as a separate matter.

    146 Included in the docket for the final rule.

    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 de minimis exemption for processed C&D wood to address small or de minimis amounts of material remaining on the wood. In response, the EPA acknowledged that “C&D-derived wood can contain de minimis amounts of contaminants and other materials provided it meets the legitimacy criterion for contaminant levels” and thus, did not find it necessary to finalize a de minimis exemption.147 That discussion supports the application of a de minimis principle.

    147 See 76 FR 15486.

    VI. Technical Corrections A. Change to 40 CFR 241.3(b)(2)

    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.

    B. Change to 40 CFR 241.3(c)(1)

    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 follows: “The determination will be based on whether the non-hazardous secondary material that has been discarded is a legitimate fuel as specified in paragraph (d)(1) of this section and on the following criteria:”

    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 that has not been discarded is a legitimate fuel as specified in paragraph (d)(1) of this section and on the following criteria . . .”

    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 that has not been discarded is a legitimate fuel as specified in paragraph (d)(1) of this section and on the following criteria . . .”

    C. Change to 40 CFR 241.3(d)(1)(iii)

    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 boiler (emphasis added), whereas the rest of the sentence refers to the combustion unit. Like a boiler, a cement kiln that combusts any non-hazardous solid waste is subject to regulation as a CISWI unit pursuant to section 129(g)(1) of the CAA. In order for a cement kiln not to be classified as a CISWI unit, it must use a fuel that is/has been determined to be a non-waste fuel under 40 CFR part 241 when combusted. Consistent with the section as a whole, the word boiler is replaced with combustion unit to clarify that a person may choose a traditional fuel that can be or is burned in a combustion unit, which can be a cement kiln, as well as a boiler. Thus, the proposed regulatory text was “. . . 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 combustion unit is permitted to burn that traditional fuel . . . .” The EPA received no comments on this technical change and is issuing the rule in final, as proposed.

    VII. Effect of This Rule on Other Programs

    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 148 for the discussion on the effect of the NHSM rule on other programs.

    148 76 FR 15456, March 21, 2011 (page 15545).

    VIII. State Authority A. Relationship to State Programs

    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 149 for the discussion on state authority including, “Applicability of State Solid Waste Definitions and Beneficial Use Determinations” and “Clarifications on the Relationship to State Programs.” The Agency, however, would like to reiterate that this rule (like the March 21, 2011 and the February 7, 2013 final rules) is not intended to interfere with a state's program authority over the general management of solid waste.

    149 76 FR 15456, March 21, 2011 (page 15546).

    B. State Adoption of the Rulemaking

    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.

    IX. Cost and Benefits

    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 150 or benefits. Rather, this RCRA proposal is being developed to simplify the rules for identifying which NHSMs are not solid wastes and to provide additional clarity and direction for owners or operators of combustion facilities. In this regard, this proposal provides a procedural benefit to the regulated community, as well as the states through the establishment of regulatory clarity and enhanced materials management certainty.

    150 Excluding minor administrative burden/cost (e.g., rule familiarization).

    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.151 A document discussing the effects of the proposed rule was available in the docket for review. No comments were received on the assessment and the document reflecting the final rule has been placed in the rulemaking docket.

    151 U.S. EPA, Office of Resource Conservation and Recovery, “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” May 22, 2015.

    X. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review

    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.

    B. Paperwork Reduction Act

    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 et seq. and has assigned OMB control number 2050-0205.

    Respondents/affected entities: Processors and combustors of C&D wood.

    Respondent's obligation to respond: Mandatory per 40 CFR 241.4(a)(5)(iii) and (iv).

    Estimated number of respondents: 605.

    Frequency of response: Annual.

    Total estimated burden: 2,252 hours (per year). Burden is defined at 5 CFR 1320.3(b).

    Total estimated cost: $230,111 (per year), includes $0 annualized capital or operation & maintenance costs.

    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 Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule.

    C. Regulatory Flexibility Act

    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.

    D. Unfunded Mandates Reform Act

    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.

    E. Executive Order 13132: Federalism

    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.

    F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments

    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.

    G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 because it is not economically significant as defined in Executive Order 12866, and because the EPA does not believe the environmental health or safety risks addressed by this action present a disproportionate risk to children. Based on the discussion below, the Agency finds that the populations of children near potentially affected boilers are either not significantly greater than national averages, or in the case of landfills, may potentially result in reduced discharges near such populations.152

    152 U.S. EPA, Office of Resource Conservation and Recovery. Summary of Environmental Justice Impacts for the Non-Hazardous Secondary Material (NHSM) Rule, the 2010 Commercial and Industrial Solid Waste Incinerator (CISWI) Standards, the 2010 Major Source Boiler NESHAP and the 2010 Area Source Boiler NESHAP. February 2011.

    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.153 We assessed the share of the population under the age of 18 living within a three-mile (approximately five kilometers) radius of these facilities.

    153 The absence of site-specific coordinates for area sources prevents assessments of the demographics of populations located near these sources.

    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.154 In addition, while the fuel source and corresponding emission mix for some of these boilers may change as an indirect response to this rule, emissions from these sources remain subject to the CAA section 112 standards.

    154 U.S. EPA, Office of Resource Conservation and Recovery. Summary of Environmental Justice Impacts for the Non-Hazardous Secondary Material (NHSM) Rule, the 2010 Commercial and Industrial Solid Waste Incinerator (CISWI) Standards, the 2010 Major Source Boiler NESHAP and the 2010 Area Source Boiler NESHAP. February 2011.

    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.

    H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

    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.

    I. National Technology Transfer and Advancement Act

    This final rulemaking does not involve technical standards.

    J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations

    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 (e.g., noise, aesthetics, water pollution, etc.). These factors were considered in conjunction with our assessment of the demographic characteristics surrounding the affected areas.

    Our environmental justice assessment 155 for the March 21, 2011 final rule, based on the most recent census data, reviewed the distributions of minority and low-income groups that might be impacted by the sources indirectly affected by this rule. We focused on census blocks within three miles (approximately five kilometers) of the indirectly affected sources. We then determined the demographic composition (e.g., race, income, etc.) of these census blocks and compared them to the corresponding national compositions. Our findings show that populations living within three miles of major source boilers represent areas with minority and low-income populations that are higher than the national averages. In these areas, the minority share 156 of the population was found to be 33 percent, compared to the national average of 25 percent. For these same areas, the percent of the population below the poverty line (16 percent) is also higher than the national average (13 percent).

    155 U.S. EPA, Office of Resource Conservation and Recovery. Summary of Environmental Justice Impacts for the Non-Hazardous Secondary Material (NHSM) Rule, the 2010 Commercial and Industrial Solid Waste Incinerator (CISWI) Standards, the 2010 Major Source Boiler NESHAP and the 2010 Area Source Boiler NESHAP. February 2011. The findings of that study, based on the most recent census data, are not expected to change as a result of this action.

    156 This figure is for overall population minus white population and does not include the Census group defined as “White Hispanic.”

    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.

    K. Congressional Review Act (CRA)

    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).

    List of Subjects in 40 CFR Part 241

    Environmental protection, Air pollution control, Waste treatment and disposal.

    Dated: January 21, 2016. Gina McCarthy, Administrator.

    For the reasons stated in the preamble, Title 40, chapter I, of the Code of Federal Regulations is amended as follows:

    PART 241—SOLID WASTES USED AS FUELS OR INGREDIENTS IN COMBUSTION UNITS 1. The authority citation for part 241 continues to read as follows: Authority:

    42 U.S.C. 6903, 6912, 7429.

    Subpart A—General
    2. Section 241.2 is amended by adding in alphabetical order the definitions “Construction and demolition (C&D) wood”, “Creosote treated railroad ties”, “Paper recycling residuals” and “Power producer” to read as follows:
    § 241.2 Definitions.

    Construction and demolition (C&D) wood means wood that is generated from the processing of debris from construction and demolition activities for the purposes of recovering wood. C&D wood from construction activities results from wood generated during any installation activity or from purchasing more wood than a project ultimately requires. C&D wood from demolition activities results from dismantling buildings and other structures, removing materials during renovation, or from natural disasters.

    Creosote treated railroad ties means railway support ties treated with a wood preservative containing creosols and phenols and made from coal tar oil.

    Paper recycling residuals means the secondary material generated from the recycling of paper, paperboard and corrugated containers composed primarily of wet strength and short wood fibers that cannot be used to make new paper and paperboard products. Paper recycling residuals that contain more than small amounts of non-fiber materials including polystyrene foam, polyethylene film, other plastics, waxes and adhesives, dyes and inks, clays, starches and other coating and filler material are not paper recycling residuals for purposes of this definition.

    Power producer means a boiler unit producing electricity for sale to the grid. The term does not include units meeting the definition of electricity generating unit under 40 CFR 63.10042.

    Subpart B—Identification of Non-Hazardous Secondary Materials That Are Solid Wastes When Used as Fuels or Ingredients in Combustion Units 3. Section 241.3 is amended by revising paragraphs (c)(1) introductory text and (d)(1)(iii) to read as follows:
    § 241.3 Standards and procedures for identification of non-hazardous secondary materials that are solid wastes when used as fuels or ingredients in combustion units.

    (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 direct comparison of the contaminant levels in both the non-hazardous secondary material and traditional fuel(s) prior to combustion.

    4. Section 241.4 is amended by adding paragraphs (a)(5) through (7) to read as follows:
    § 241.4 Non-waste Determinations for Specific Non-Hazardous Secondary Materials When Used as a Fuel.

    (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 (e.g., polyvinyl chloride and other plastics, drywall, concrete, aggregates, dirt, and asbestos), and wood treated with creosote, pentachlorophenol, chromated copper arsenate, or other copper, chromium, or arsenical preservatives. In addition:

    (i) Positive sorting. C&D processing facilities that use positive sorting—where operators pick out desirable wood from co-mingled debris—or that receive and process positive sorted C&D wood must either:

    (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) Negative sorting. C&D processing facilities that use negative sorting—where operators remove contaminated or otherwise undesirable materials from co-mingled debris—must remove fines (i.e., small-sized particles that may contain relatively high concentrations of lead and other contaminants) and either:

    (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) Training. Processors 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 date of training held and must be maintained on-site for a period of three years.

    (iv) Written certification. 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.

    (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 (e.g. oil delivery mechanisms are removed) in order to use natural gas instead of fuel oil, as part of normal operations and not solely as part of start-up or shut-down operations. The CTRTs may continue to be combusted as product fuel under this subparagraph only if the following conditions are met, which are intended to ensure that the CTRTs are not being discarded:

    (A) CTRTs must be burned in existing (i.e. commenced construction prior to April 14, 2014) stoker, bubbling bed, fluidized bed, or hybrid suspension grate boilers; and

    (B) CTRTs can comprise no more than 40 percent of the fuel that is used on an annual heat input basis.

    [FR Doc. 2016-01866 Filed 2-5-16; 8:45 am] BILLING CODE 6560-50-P
    CategoryRegulatory Information
    CollectionFederal Register
    sudoc ClassAE 2.7:
    GS 4.107:
    AE 2.106:
    PublisherOffice of the Federal Register, National Archives and Records Administration

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