Page Range | 64305-65119 | |
FR Document |
Page and Subject | |
---|---|
80 FR 64354 - Suspension of Community Eligibility | |
80 FR 64312 - Airworthiness Directives; Honeywell International Inc. Turboprop Engines (Type Certificate Previously Held by AlliedSignal Inc., Garrett Engine Division; Garrett Turbine Engine Company; and AiResearch Manufacturing Company of Arizona) | |
80 FR 65117 - Continuation of the National Emergency With Respect to the Situation in or in Relation to the Democratic Republic of the Congo | |
80 FR 64305 - Delegation of Authority for Drafting and Submission of the International Trade Data System Annual Report to the Congress | |
80 FR 64491 - Caldwell Railroad Commission-Abandonment Exemption-in Caldwell County, NC | |
80 FR 64416 - Sunshine Act; Notice of Meeting | |
80 FR 64385 - Notice of Request for Revision to and Extension of Approval of an Information Collection; Importation of Citrus From Peru | |
80 FR 64386 - Notice of Decision To Authorize the Importation of Fresh Pitahaya From Israel Into the Continental United States | |
80 FR 64443 - U.S. Extractive Industries Transparency Initiative Advisory Committee Request for Nominees | |
80 FR 64387 - Notice of Determination of the Classical Swine Fever, Foot-and-Mouth Disease, Rinderpest, and Swine Vesicular Disease Status of Croatia | |
80 FR 64443 - Indian Gaming | |
80 FR 64442 - Indian Gaming | |
80 FR 64392 - Uncovered Innerspring Units From the People's Republic of China: Affirmative Preliminary Determination of Circumvention of the Antidumping Duty Order | |
80 FR 64454 - Proposed Submission of Information Collection for OMB Review; Comment Request; Locating and Paying Participants | |
80 FR 64449 - Notice Pursuant to the National Cooperative Research and Production Act of 1993-Sematech, Inc. D/B/A International Sematech | |
80 FR 64398 - Agency Information Collection Activities: Submission for OMB Review; Comment Request | |
80 FR 64399 - Agency Information Collection Activities: Submission for OMB Review; Comment Request | |
80 FR 64453 - Information Collection: Exemptions and Continued Regulatory Authority in Agreement States and in Offshore Waters Under Section 274 | |
80 FR 64435 - National Boating Safety Advisory Council | |
80 FR 64400 - Judicial Proceedings Since Fiscal Year 2012 Amendments Panel (Judicial Proceedings Panel); Notice of Federal Advisory Committee Meeting | |
80 FR 64409 - Environmental Impact Statements; Notice of Availability | |
80 FR 64415 - Petition of Pacific International Lines and Mariana Express Lines for an Exemption From Commission Regulations; Notice of Filing and Request for Comments | |
80 FR 64491 - Martin Marietta Materials, Inc.-Acquisition of Control Exemption-Rock & Rail, Inc. | |
80 FR 64448 - Notice Pursuant to the National Cooperative Research and Production Act of 1993-Advanced Media Workflow Association, Inc. | |
80 FR 64448 - Notice Pursuant to the National Cooperative Research and Production Act of 1993-Cooperative Research Group on Separation Technology Research Program | |
80 FR 64449 - Notice Pursuant to the National Cooperative Research and Production Act of 1993-Cooperative Research Group on Advanced Engine Fluids | |
80 FR 64449 - Notice Pursuant to the National Cooperative Research and Production Act of 1993-AllSeen Alliance, Inc. | |
80 FR 64433 - Collection of Information Under Review by Office of Management and Budget; OMB Control Number: 1625-0095 | |
80 FR 64450 - Notice Pursuant to the National Cooperative Research and Production Act of 1993-Members of SGIP 2.0, Inc. | |
80 FR 64437 - Information Collection Request to Office of Management and Budget; OMB Control Number: 1625-0112 | |
80 FR 64508 - Multiemployer Pension Plan Application To Reduce Benefits | |
80 FR 64477 - Final Designation of the Highway Primary Freight Network | |
80 FR 64404 - Notice of Intent To Prepare a Draft Environmental Impact Statement for the Sacramento River Flood Control Project, California, General Reevaluation | |
80 FR 64409 - Certain New Chemicals; Receipt and Status Information for August 2015 | |
80 FR 64418 - Medicare Program; Expansion of Prior Authorization for Repetitive Scheduled Non-Emergent Ambulance Transports | |
80 FR 64490 - Buy America Waiver Notification | |
80 FR 64319 - Appointment of Foreign Service Officers | |
80 FR 64353 - Change of Address for the Interior Board of Indian Appeals | |
80 FR 64448 - Notice Pursuant to the National Cooperative Research and Production Act of 1993-Petroleum Environmental Research Forum | |
80 FR 64437 - 30-Day Notice of Proposed Information Collection: Continuum of Care Homeless Assistance Grant Application | |
80 FR 64438 - 30-Day Notice of Proposed Information Collection: Loan Guarantee Recovery Fund Established Pursuant to the Church Arson Prevention Act of 1996 | |
80 FR 64434 - Information Collection Request to Office of Management and Budget; OMB Control Number: 1625-0016 | |
80 FR 64430 - Information Collection Request to Office of Management and Budget; OMB Control Number: 1625-0001 | |
80 FR 64431 - Collection of Information Under Review by Office of Management and Budget; OMB Control Number: 1625-0035 | |
80 FR 64434 - Collection of Information Under Review by Office of Management and Budget; OMB Control Number: 1625-0014 | |
80 FR 64429 - Information Collection Request to Office of Management and Budget; OMB Control Number: 1625-0039 | |
80 FR 64307 - Importation of Fresh Peppers From Ecuador Into the United States | |
80 FR 64401 - Privacy Act of 1974; System of Records | |
80 FR 64403 - Defense Health Board; Notice of Federal Advisory Committee Meeting | |
80 FR 64415 - Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company | |
80 FR 64307 - Solicitation of Federal Civilian and Uniformed Service Personnel for Contributions to Private Voluntary Organizations | |
80 FR 64454 - Submission for Review: Health Benefits Election Form | |
80 FR 64396 - Pacific Fishery Management Council; Online Webinar | |
80 FR 64395 - South Atlantic Fishery Management Council (Council); Public Hearings | |
80 FR 64394 - New England Fishery Management Council; Public Meeting | |
80 FR 64394 - Mid-Atlantic Fishery Management Council (MAFMC); Public Meeting | |
80 FR 64396 - Magnuson-Stevens Act Provisions; General Provisions for Domestic Fisheries; Application for Exempted Fishing Permits | |
80 FR 64370 - Energy Conservation Program: Energy Conservation Standards for Residential Furnaces | |
80 FR 64370 - Energy Conservation Program: Energy Conservation Standards for Refrigerated Beverage Vending Machines | |
80 FR 64445 - Draft Environmental Impact Statement Non-Federal Oil and Gas Regulations | |
80 FR 64405 - Meeting; President's Council of Advisors on Science and Technology | |
80 FR 64445 - Notice of Meeting, Northwest Resource Advisory Council's Travel Management Sub-Group | |
80 FR 64399 - Proposed Information Collection; Comment Request | |
80 FR 64446 - Commerce in Explosives; 2015 Annual List of Explosive Materials | |
80 FR 64416 - Formations of, Acquisitions by, and Mergers of Bank Holding Companies | |
80 FR 64491 - Terminal Railroad Association of St. Louis-Trackage Rights Exemption-Norfolk Southern Railway Company | |
80 FR 64421 - Agency Information Collection Activities; Announcement of Office of Management and Budget Approval; Medical Device Labeling Regulations | |
80 FR 64422 - Agency Information Collection Activities; Proposed Collection; Comment Request; Guidance on Informed Consent for In Vitro Diagnostic Device Studies Using Leftover Human Specimens That Are Not Individually Identifiable | |
80 FR 64477 - Buy America Waiver Notification | |
80 FR 64444 - Notice of Public Meeting for the Eastern Washington Resource Advisory Council | |
80 FR 64394 - Submission for OMB Review; Comment Request | |
80 FR 64493 - Privacy Act of 1974; Department of Transportation/ALL 8, Parking and Transit Benefit System | |
80 FR 64495 - Funding Opportunity Title: Notice of Allocation Availability (NOAA) Inviting Applications for the Calendar Year (CY) 2015 Allocation Round of the New Markets Tax Credit (NMTC) Program | |
80 FR 64324 - Drawbridge Operation Regulations; York River, Yorktown, VA | |
80 FR 64382 - International Fisheries; Western and Central Pacific Fisheries for Highly Migratory Species; Treatment of U.S. Purse Seine Fishing With Respect to U.S. Territories | |
80 FR 64451 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Prohibited Transaction Exemption 1990-1, Insurance Company Pooled Separate Accounts | |
80 FR 64406 - Combined Notice of Filings | |
80 FR 64406 - Combined Notice of Filings #2 | |
80 FR 64407 - Combined Notice of Filings #1 | |
80 FR 64318 - Establishment of Class E Airspace; Vancouver, WA | |
80 FR 64317 - Establishment of Class E Airspace; Vidalia, LA | |
80 FR 64450 - Employment and Training Administration | |
80 FR 64316 - Revocation of Class E Airspace; Vincennes, IN | |
80 FR 64416 - Privacy Act of 1974; Notice of an Updated System of Records | |
80 FR 64475 - North American Free Trade Agreement; Invitation for Applications for Inclusion on the Chapter 19 Roster | |
80 FR 64344 - Approval and Promulgation of Implementation Plans; Florida; Regional Haze Plan Amendment-Lakeland Electric C.D. McIntosh | |
80 FR 64505 - Proposed Collection; Comment Request for Revenue Procedure 2011-4, Revenue Procedure 2011-5, Revenue Procedure 2011-6, and Revenue Procedure 2011-8 | |
80 FR 64506 - Proposed Collection; Comment Request for Notice 2009-31 and Revenue Procedure 2009-43 | |
80 FR 64428 - National Institute of Mental Health; Notice of Closed Meetings | |
80 FR 64429 - National Institute of Allergy and Infectious Diseases; Notice of Closed Meetings | |
80 FR 64429 - National Institute on Drug Abuse; Notice of Closed Meeting | |
80 FR 64428 - National Institute on Drug Abuse; Notice of Closed Meetings | |
80 FR 64428 - Eunice Kennedy Shriver National Institute of Child Health and Human Development; Notice of Meeting | |
80 FR 64425 - Center for Scientific Review; Notice of Closed Meetings | |
80 FR 64425 - National Eye Institute; Notice of Closed Meeting. | |
80 FR 64455 - New Postal Product | |
80 FR 64423 - Agency Information Collection Activities; Announcement of Office of Management and Budget Approval; Medical Device Recall Authority | |
80 FR 64421 - Agency Information Collection Activities; Announcement of Office of Management and Budget Approval; MedWatch: The Food and Drug Administration Medical Products Reporting Program | |
80 FR 64324 - Drawbridge Operation Regulation; Snohomish River, Marysville, WA | |
80 FR 64507 - Proposed Collection; Comment Request for Forms 5498-QA and 1099-QA | |
80 FR 64468 - Investment Company Act Release No. 31870; File No. 812-14536 Advisors Asset Management, Inc. and AAM ETF Trust; Notice of Application | |
80 FR 64469 - Self-Regulatory Organizations; Chicago Board Options Exchange, Incorporated; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend the Fees Schedule | |
80 FR 64464 - Self-Regulatory Organizations; NASDAQ OMX PHLX LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change Relating to Mini Options | |
80 FR 64458 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change Relating to the Series 28 Examination Program | |
80 FR 64465 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change Relating to the Series 27 Examination Program | |
80 FR 64456 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change Relating to the New Securities Trader Qualification Examination (Series 57) | |
80 FR 64462 - Self-Regulatory Organizations; NASDAQ OMX PHLX LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change Relating to the Options Floor Broker Management System | |
80 FR 64461 - Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Withdrawal of a Proposed Rule Change, as Modified by Amendment No. 1 Thereto, To Amend NYSE Arca Equities Rule 8.600 To Adopt Generic Listing Standards for Managed Fund Shares | |
80 FR 64507 - Proposed Collection; Comment Request; Office of Investment Security | |
80 FR 64456 - Removal of Global Direct Contracts From the Competitive Product List | |
80 FR 64423 - Public Meeting of the Presidential Commission for the Study of Bioethical Issues | |
80 FR 64424 - Meeting of the Advisory Committee on Blood and Tissue Safety and Availability | |
80 FR 64474 - Washington Disaster #WA-00060 | |
80 FR 64474 - South Carolina Disaster #SC-00032 | |
80 FR 64408 - Dominion Transmission, Inc.; Notice of Application | |
80 FR 64408 - Joint Meeting of the Nuclear Regulatory Commission and the Federal Energy Regulatory Commission; Notice of Joint Meeting of the Federal Energy Regulatory Commission and the Nuclear Regulatory Commission | |
80 FR 64397 - Atlantic Coastal Fisheries Cooperative Management Act Provisions; Horseshoe Crabs; Application for Exempted Fishing Permit, 2015; Reopening of Comment Period | |
80 FR 64472 - Data Collection Available for Public Comments | |
80 FR 64473 - Data Collection Available for Public Comments | |
80 FR 64474 - Data Collection Available for Public Comments | |
80 FR 64385 - Submission for OMB Review; Comment Request | |
80 FR 64378 - Definition of Terms Relating to Marital Status | |
80 FR 64440 - Endangered Species; Marine Mammals; Issuance of Permits | |
80 FR 64441 - Endangered Species; Receipt of Applications for Permit | |
80 FR 64452 - Proposed Collection; Comment Request | |
80 FR 64381 - Petitions for Reconsideration of Action in Rulemaking Proceeding | |
80 FR 64309 - Competitive and Noncompetitive Non-Formula Federal Assistance Programs-Specific Administrative Provisions for the Food Insecurity Nutrition Incentive Grants Program | |
80 FR 64325 - Alaska; Hunting and Trapping in National Preserves | |
80 FR 64415 - Pesticide Program Dialogue Committee; Notice of Charter Renewal | |
80 FR 64373 - Airworthiness Directives; Engine Alliance Turbofan Engines | |
80 FR 64439 - Federal Property Suitable as Facilities To Assist the Homeless | |
80 FR 64371 - Airworthiness Directives; Airbus Airplanes | |
80 FR 64375 - Airworthiness Directives; Airbus Airplanes | |
80 FR 64361 - Acquisition Regulations: Export Control | |
80 FR 64492 - Privacy Act of 1974; Department of Transportation, Office of the Secretary of Transportation; DOT/ALL-18, International Freight Data System (IFDS) | |
80 FR 64314 - Airworthiness Directives; Technify Motors GmbH Reciprocating Engines | |
80 FR 64312 - Airworthiness Directives; Pratt & Whitney Turbofan Engines | |
80 FR 64346 - Approval and Promulgation of Implementation Plans; Oregon: Lane Regional Air Protection Agency Open Burning Rules and Oregon Department of Environmental Quality Enforcement Procedures | |
80 FR 64381 - Approval and Promulgation of Implementation Plans; Oregon: Lane Regional Air Protection Agency Open Burning Rules and Oregon Department of Environmental Quality Enforcement Procedures | |
80 FR 64354 - Broadcast Licensee-Conducted Contests | |
80 FR 64965 - Federal Plan Requirements for Greenhouse Gas Emissions From Electric Utility Generating Units Constructed on or Before January 8, 2014; Model Trading Rules; Amendments to Framework Regulations | |
80 FR 64661 - Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units | |
80 FR 64509 - Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units |
Agricultural Marketing Service
Animal and Plant Health Inspection Service
National Institute of Food and Agriculture
International Trade Administration
National Oceanic and Atmospheric Administration
Engineers Corps
Federal Energy Regulatory Commission
Centers for Medicare & Medicaid Services
Food and Drug Administration
Indian Health Service
National Institutes of Health
Coast Guard
Federal Emergency Management Agency
Fish and Wildlife Service
Indian Affairs Bureau
Land Management Bureau
National Park Service
Alcohol, Tobacco, Firearms, and Explosives Bureau
Antitrust Division
Employment and Training Administration
National Endowment for the Arts
Federal Aviation Administration
Federal Highway Administration
Surface Transportation Board
Community Development Financial Institutions Fund
Internal Revenue Service
Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, and notice of recently enacted public laws.
To subscribe to the Federal Register Table of Contents LISTSERV electronic mailing list, go to http://listserv.access.thefederalregister.org and select Online mailing list archives, FEDREGTOC-L, Join or leave the list (or change settings); then follow the instructions.
Office of Personnel Management.
Final rule; delay of effective date.
The United States Office of Personnel Management (OPM) is issuing a final rule to change the effective date of previously published Combined Federal Campaign regulations to January 1, 2017.
The effective date of the regulations published in the
Regarding funds contributed to the CFC during the 2016 campaign year, LFCCs and PCFOs will continue to operate, disburse funds, and submit to compliance requirements in accordance with regulations in 5 CFR part 950 as amended at 71 FR 67284, Nov. 20, 2006.
Mary Capule by telephone at (202) 606-2564; by FAX at (202) 606-5056; or by email at
The U.S. Office of Personnel Management (OPM) issued a Notice of Proposed Rulemaking on August 17, 2015 to amend 5 CFR part 950 to change the effective date of the new rule from January 1, 2016 to January 1, 2017. During the comment period, OPM received two comments, including one from a Federal agency and one from a Local Federal Coordinating Committee (LFCC). These comments are addressed below.
The Department of Defense expressed its support for the amendment to allow additional time to test new systems before they are deployed. The Greater Arkansas CFC LFCC requested clarification on the process by which a contract will be awarded to a vendor to serve as the Central Campaign Administrator and the method by which the system will be tested.
The revision involves the change of the effective date of the new CFC regulations published in the
On August 17, 2015 (80 FR 49173), OPM published a proposed rule with requests for public comment in the
I certify that this regulation will not have a significant economic impact on a substantial number of small entities. Charitable organizations applying to the CFC have an existing, independent obligation to comply with the eligibility and public accountability standards contained in current CFC regulations. Streamlining these standards will be less burdensome.
This rule has been reviewed by the Office of Management and Budget in accordance with Executive Orders 12866 and 13563.
Administrative practice and procedures, Charitable contributions, Government employees, Military personnel, Nonprofit organizations and Reporting and recordkeeping requirements.
Animal and Plant Health Inspection Service, USDA.
Final rule.
We are amending the fruits and vegetables regulations to allow the importation of fresh peppers into the United States from Ecuador. As a condition of entry, the fruit will have to be produced in accordance with a systems approach that includes requirements for fruit fly trapping, pre-harvest inspections, production sites, and packinghouse procedures designed to exclude quarantine pests. The fruit will also be required to be imported in commercial consignments and accompanied by a phytosanitary certificate issued by the national plant protection organization of Ecuador stating that the consignment was produced and prepared for export in accordance with the requirements in the systems approach. This action allows for the importation of fresh peppers from Ecuador while continuing to provide protection against the introduction of plant pests into the United States.
Effective November 23, 2015.
Ms. Claudia Ferguson, Senior Regulatory Policy Specialist, Regulatory Coordination and Compliance, PPQ, APHIS, 4700 River Road Unit 133, Riverdale, MD 20737-1236; (301) 851-2352;
Under the regulations in “Subpart-Fruits and Vegetables” (7 CFR 319.56-1 through 319.56-73, referred to below as the regulations), the Animal and Plant Health Inspection Service (APHIS) of the U.S. Department of Agriculture prohibits or restricts the importation of fruits and vegetables into the United
On April 24, 2015, we published in the
In the proposed rule, we noted that the PRA rated six plant pests as having a high pest risk potential for following the pathway of peppers from Ecuador into the United States: The insects
We determined in the PRA that measures beyond standard port of arrival inspection will mitigate the risks posed by these plant pests and proposed a systems approach that includes requirements for fruit fly trapping, pre-harvest inspections, production sites, and packinghouse procedures designed to exclude quarantine pests. We also proposed that the fruit be imported in commercial consignments only and accompanied by a phytosanitary certificate issued by the national plant protection organization of Ecuador stating that the consignment was produced and prepared for export in accordance with the systems approach.
We solicited comments concerning our proposal for 60 days ending June 23, 2015. We did not receive any comments.
We have made one minor change to this final rule,
Therefore, for the reasons given in the proposed rule, we are adopting the proposed rule as a final rule with the change noted.
This final rule has been determined to be not significant for the purposes of Executive Order 12866 and, therefore, has not been reviewed by the Office of Management and Budget.
In accordance with the Regulatory Flexibility Act, we have analyzed the potential economic effects of this action on small entities. The analysis is summarized below. Copies of the full analysis are available by contacting the person listed under
This rule amends the regulations to allow the importation of fresh peppers from Ecuador into the United States when a systems approach to pest risk mitigation is used to prevent the introduction of quarantine pests. The systems approach will integrate prescribed mitigation measures that cumulatively achieve the appropriate level of phytosanitary protection.
The most recent production data available show that fresh pepper yields in Ecuador have expanded from approximately 12,522 pounds per hectare (pounds/ha) in 1996 to approximately 66,361 pounds/ha in 2006. The total quantity of fresh peppers that were exported from Ecuador in 2006 and 2007 was 96.3 metric tons (MT) and 206.5 MT, respectively. Sea shipping containers that are 40 feet in length hold approximately 20 U.S. MT. Considering the total volume exported from Ecuador during these years, APHIS estimates imports of no more than 10 containers (200 MT) of fresh peppers from Ecuador into the United States annually. This quantity is equivalent to less than 0.02 percent of annual U.S. fresh pepper production. Similarly, the estimated quantity of fresh pepper imports from Ecuador (200 MT annually) is minimal compared to the total quantity of fresh peppers imported by the United States in recent years (800,000 MT annually).
In the United States, the average value of bell pepper production per farm in 2012 was approximately $52,300, and the average value of chili pepper production per farm was approximately $20,700. Both levels are well below the small-entity standard of $750,000. Establishments classified within NAICS 111219, including pepper farms, are considered small by the Small Business Administration (SBA) if annual sales are not more than $750,000. Accordingly, pepper growers are predominantly small entities according to the SBA standard. Under these circumstances, the Administrator of the Animal and Plant Health Inspection Service has determined that this action will not have a significant economic impact on a substantial number of small entities.
This final rule allows fresh pepper fruit to be imported into the United States from Ecuador. State and local laws and regulations regarding fresh pepper fruit imported under this rule will be preempted while the fruit is in foreign commerce. Fresh fruits are generally imported for immediate distribution and sale to the consuming public, and remain in foreign commerce until sold to the ultimate consumer. The question of when foreign commerce ceases in other cases must be addressed on a case-by-case basis. No retroactive effect will be given to this rule, and this rule will not require administrative proceedings before parties may file suit in court challenging this rule.
In accordance with section 3507(d) of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The Animal and Plant Health Inspection Service is committed to compliance 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. For information pertinent to E-Government Act compliance related to this rule, please contact Ms. Kimberly Hardy, APHIS' Information Collection Coordinator, at (301) 851-2727.
Coffee, Cotton, Fruits, Imports, Logs, Nursery stock, Plant diseases and pests, Quarantine, Reporting and recordkeeping requirements, Rice, Vegetables.
Accordingly, we are amending 7 CFR part 319 as follows:
7 U.S.C. 450 and 7701-7772, and 7781-7786; 21 U.S.C. 136 and 136a; 7 CFR 2.22, 2.80, and 371.3.
Fresh peppers (
(a)
(b)
(c)
(2) All production sites that participate in the pepper export program must be registered with the NPPO of Ecuador.
(3) The production sites must be inspected prior to each harvest by the NPPO of Ecuador or its approved designee in accordance with the operational workplan. If any quarantine pests are found to be generally infesting or infecting the production site, the NPPO of Ecuador will immediately prohibit that production site from exporting peppers to the United States and notify APHIS of this action. The prohibition will remain in effect until the NPPO of Ecuador and APHIS agree that the pest risk has been mitigated. If a designee conducts the program, the designation must be detailed in the operational workplan. The approved designee can be a contracted entity, a coalition of growers, or the growers themselves.
(4) The registered production sites must conduct trapping for the fruit flies
(5) If a single
(6) The NPPO of Ecuador must maintain records of trap placement, checking of traps, and any quarantine pest captures in accordance with the operational workplan. Trapping records must be maintained for APHIS review for at least 1 year.
(7) The NPPO of Ecuador must maintain a quality control program, approved by APHIS, to monitor or audit the trapping program in accordance with the operational workplan.
(d)
(2) The peppers must be packed within 24 hours of harvest in a pest-exclusionary packinghouse. The peppers must be safeguarded by an insect-proof mesh screen or plastic tarpaulin while in transit to the packinghouse and while awaiting packing. The peppers must be packed in insect-proof cartons or containers, or covered with insect-proof mesh or plastic tarpaulin, for transit into the United States. These safeguards must remain intact until arrival in the United States or the consignment will be denied entry into the United States.
(3) During the time the packinghouse is in use for exporting peppers to the United States, the packinghouse may only accept peppers from registered approved production sites.
(e)
National Institute of Food and Agriculture, USDA.
Final rule.
The National Institute of Food and Agriculture (NIFA) is publishing a final rule for the Food Insecurity Nutrition Incentive Grants Program. This final rule adds a subpart entitled “Food Insecurity Nutrition Incentive Grants Program” to the part entitled “Competitive and Noncompetitive Non-formula Federal Assistance Programs—General Award Administrative Provisions”.
This final rule becomes effective on October 23, 2015.
Lisa Scott-Morring, Policy Branch Chief, Policy and Oversight Division, Phone: 202-401-4515, Email:
The Food Insecurity Nutrition Incentive Program (FINI) is authorized under section 4405 of the Food, Conservation, and Energy Act of 2008 (7 U.S.C. 7517), as added by section 4208 of the Agricultural Act of 2014 (Pub. L. 113-79).
A primary function of NIFA is the fair, effective, and efficient
NIFA organized part 3430 as follows: Subparts A through E provide administrative provisions for all competitive and noncompetitive non-capacity 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; and (7) matching requirements. 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 (
This action has been determined to be not significant for purposes of Executive Order 12866. The rule will not create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; nor will it materially alter the budgetary impact of entitlements, grants, user fees, or loan programs; nor will it have an annual effect on the economy of $100 million or more; nor will it adversely affect the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or Tribal governments or communities in a material way. Further, it does not raise a novel legal or policy issue arising out of legal mandates, the President's priorities, or principles set forth in the Executive Order.
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 rule will not have a significant economic impact on a substantial number of small entities. The rule does not involve regulatory and informational requirements regarding businesses, organizations, and governmental jurisdictions subject to regulation.
The Department certifies that this final rule has been assessed in accordance with the requirements of the Paperwork Reduction Act, 44 U.S.C. 3501
This final rule applies to the following Federal financial assistance programs administered by NIFA: CFDA No. 10.331 Food Insecurity Nutrition Incentive Grants Program.
The Department has reviewed this final rule in accordance with the requirements of Executive Order No. 13132 and the Unfunded Mandates Reform Act of 1995, 2 U.S.C. 1501
Executive Order 12866 and the President's Memorandum of June 1, 1998, require each agency to write all rules in plain language. The Department invites comments on how to make this final rule easier to understand.
Administrative practice and procedure, Agricultural research, Grant programs—agriculture, Privacy, Reporting and recordkeeping requirements.
Accordingly, 7 CFR part 3430 is amended as set forth below:
7 U.S.C. 3316; Pub. L. 106-107 (31 U.S.C. 6101 note).
The regulations in this subpart apply to the Food Insecurity Nutrition Incentive (FINI) grants program authorized under section 4405 of the Food, Conservation, and Energy Act of 2008 (7 U.S.C. 7517), as added by section 4208 of the Agricultural Act of 2014 (Pub. L. 113-79).
The primary goal of the FINI grants program is to fund and evaluate projects intended to increase the purchase of
The definitions applicable to the FINI grants program under this subpart include:
(1) The age, sex, race, occupation, or other demographic variables of the target population;
(2) The program's organization, funding, and staffing; and
(3) The program's location and timing. Process evaluation focuses on program activities rather than outcomes.
(1) The public;
(2) A specific group of individuals; or
(3) The membership of the nonprofit.
(a)
(1) An emergency feeding organization;
(2) An agricultural cooperative;
(3) A producer network or association;
(4) A community health organization;
(5) A public benefit corporation;
(6) An economic development corporation;
(7) A farmers' market;
(8) A community-supported agriculture program;
(9) A buying club;
(10) A SNAP-authorized retailer; and
(11) A State, local, or tribal agency.
(b)
(i) Have the support of the State SNAP agency;
(ii) Would increase the purchase of fruits and vegetables by low-income consumers participating in SNAP by providing incentives at the point of purchase;
(iii) Operate through authorized SNAP retailers and comply with all relevant SNAP regulations and operating requirements;
(iv) Agree to participate in the FINI comprehensive program evaluation;
(v) Ensure that the same terms and conditions apply to purchases made by individuals with SNAP benefits and with incentives under the FINI grants program as apply to purchases made by individuals who are not members of households receiving benefits as provided in § 278.2(b) of this title; and
(vi) Include effective and efficient technologies for benefit redemption systems that may be replicated in other States and communities.
(2)
(i) Have experience:
(A) In efforts to reduce food insecurity in the community, including food distribution, improving access to services, or coordinating services and programs; or
(B) With the SNAP program;
(ii) Demonstrate competency to implement a project, provide fiscal accountability, collect data, and prepare reports and other necessary documentation;
(iii) Secure the commitment of the State SNAP agency to cooperate with the project; and
(iv) Possess a demonstrated willingness to share information with
(c)
(1) To propose projects that will provide employees with important job skills; and
(2) To have experience the following areas:
(i) Community food work, particularly concerning small and medium-size farms, including the provision of food to people in low-income communities and the development of new markets in low-income communities for agricultural producers; and
(ii) Job training and business development activities for food-related activities in low-income communities.
(d)
(a)
(b)
(c)
(a)
(b)
(a)
(b)
(c)
(d)
The term of a grant under this subpart may not exceed 5 years. No-cost extensions of time beyond the maximum award terms will not be considered or granted.
(a)
(1) Maximize the share of funds used for direct incentives to participants;
(2) Use direct-to-consumer sales marketing;
(3) Demonstrate a track record of designing and implementing successful nutrition incentive programs that connect low-income consumers and agricultural producers;
(4) Provide locally or regionally produced fruits and vegetables;
(5) Are located in underserved communities; or
(6) Address other criteria as established by NIFA and included in the requests for applications.
(b)
In rule document 2015-25606, appearing on pages 61091 through 61093 in the issue of Friday, October 9, 2015, make the following correction:
On page 61093, at the top of the page, the image heading “Figure 2 to Paragraph (e)—Airplane Operating Procedures” should read “Figure 1 to Paragraph (e)—Airplane Operating Procedures”.
Federal Aviation Administration (FAA), DOT.
Final rule.
We are adopting a new airworthiness directive (AD) for certain Pratt & Whitney (PW) PW4164, PW4168, PW4168A, PW4164-1D, PW4168-1D, PW4168A-1D, and PW4170 turbofan engines. This AD was prompted by crack finds in the 6th stage low-pressure turbine (LPT) disk. This AD requires
This AD is effective November 27, 2015.
The Director of the Federal Register approved the incorporation by reference of a certain publication listed in this AD as of November 27, 2015.
For service information identified in this AD, contact Pratt & Whitney, 400 Main St., East Hartford, CT 06108; phone: 860-565-8770; fax: 860-565-4503. You may view this service information at the FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA. For information on the availability of this material at the FAA, call 781-238-7125. It is also available on the Internet at
You may examine the AD docket on the Internet at
Besian Luga, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7750; fax: 781-238-7199; email:
We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 by adding an AD that would apply to all PW PW4164, PW4168, PW4168A, PW4164-1D, PW4168-1D, PW4168A-1D, and PW4170 turbofan engines. The NPRM published in the
We gave the public the opportunity to participate in developing this AD. The following presents the comment received on the NPRM (80 FR 32316, June 8, 2015) and the FAA's response to this comment.
An individual commenter requested that we define “LPT shop visit” more precisely to prevent unnecessary discussions regarding its meaning.
We agree. We revised the definition to read: “For the purpose of this AD, an “LPT shop visit” is defined as the removal of the 6th stage disk from the LPT rotor and the removal of the blades from the disk.”
We reviewed the relevant data, considered the comment received, and determined that air safety and the public interest require adopting this AD with the change described previously.
We reviewed PW Service Bulletin (SB) No. PW4G-100-72-252, dated November 18, 2014. The SB provides a list of PW 6th stage LPT disks affected by this AD. This service information is reasonably available because the interested parties have access to it through their normal course of business or see
We estimate that this AD affects 18 engines installed on airplanes of U.S. registry. We also estimate that no additional hours will be required per engine to comply with this AD because the engine is already disassembled in the shop when we require the part to be removed. The average labor rate is $85 per hour. We estimate that 6 engines will require replacement parts during an LPT shop visit, and that the prorated replacement parts cost will be $108,800 per engine. Based on these figures, we estimate the cost of this AD on U.S. operators to be $652,800.
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.
This AD will not have federalism implications under Executive Order 13132. This AD will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify that this AD:
(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),
(3) Will not affect intrastate aviation in Alaska to the extent that it justifies making a regulatory distinction, and
(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD is effective November 27, 2015.
None.
This AD applies to all Pratt & Whitney (PW) PW4164, PW4168, PW4168A, PW4164-1D, PW4168-1D, PW4168A-1D, and PW4170 turbofan engines with 6th stage low-pressure turbine (LPT) disks, part number 50N886, installed.
This AD was prompted by crack finds in the 6th stage LPT disk. We are issuing this AD to prevent failure of the 6th stage LPT disk, which could lead to an uncontained disk release, damage to the engine, and damage to the airplane.
Comply with this AD within the compliance times specified, unless already done. At the next LPT shop visit after the effective date of this AD, remove from service 6th stage LPT disks with serial numbers listed in the Accomplishment Instructions, Table 1, of PW Service Bulletin No. PW4G-100-72-252, dated November 18, 2014.
For the purpose of this AD, an “LPT shop visit” is defined as the removal of the 6th stage disk from the LPT rotor and the removal of the blades from the disk.
The Manager, Engine Certification Office, FAA, may approve AMOCs for this AD. Use the procedures found in 14 CFR 39.19 to make your request. You may email your request to:
For more information about this AD, contact Besian Luga, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7750; fax: 781-238-7199; email:
(1) The Director of the Federal Register approved the incorporation by reference (IBR) of the service information listed in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.
(2) You must use this service information as applicable to do the actions required by this AD, unless the AD specifies otherwise.
(3) The following service information was approved for IBR on November 27, 2015.
(i) Pratt & Whitney (PW) Service Bulletin No. PW4G-100-72-252, dated November 18, 2014.
(ii) Reserved.
(4) For PW service information identified in this AD, contact Pratt & Whitney, 400 Main St., East Hartford, CT 06108; phone: 860-565-8770; fax: 860-565-4503.
(5) You may view this service information at FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA. For information on the availability of this material at the FAA, call 781-238-7125.
(6) You may view this service information at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:
Federal Aviation Administration (FAA), DOT.
Final rule.
We are adopting a new airworthiness directive (AD) for all Technify Motors GmbH TAE 125-02 reciprocating engines with a dual mass flywheel installed. This AD requires installation of a start phase monitoring system and associated specified software. This AD was prompted by reports of a gearbox drive shaft breaking during starting or restarting of the engine. We are issuing this AD to prevent overload and failure of the gearbox drive shaft, which could result in failure of the engine, in-flight shutdown, and loss of control of the airplane.
This AD becomes effective November 27, 2015.
The Director of the Federal Register approved the incorporation by reference of a certain publication listed in this AD as of November 27, 2015.
For service information identified in this AD, contact Technify Motors GmbH, Platanenstrasse 14, D-09356 Sankt Egidien, Germany; phone: +49 37204 696 0; fax: +49 37204 696 29125; email:
You may examine the AD docket on the Internet at
Robert Green, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7754; fax: 781-238-7199; email:
We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 by adding an AD that would apply to the specified products. The NPRM was published in the
Cases of a broken gearbox drive shaft have been reported on aeroplanes equipped with TAE 125-02 engines that have a Dual Mass Flywheel installed.
Investigations results showed a possible overload of the gearbox drive shaft during starting of the engine or during restarting of the engine in-flight.
This condition, if not corrected, could lead to engine power loss during flight, possibly resulting in loss of control of the aeroplane.
We gave the public the opportunity to participate in developing this AD. We received no comments on the NPRM (80 FR 38990, July 8, 2015).
We reviewed the available data and determined that air safety and the public interest require adopting this AD as proposed.
Technify Motors GmbH has issued Service Bulletin No. SB TMG 125-1018 P1, Revision 1, dated February 5, 2015. The service information describes procedures for installing a start phase monitoring system and associated specified software mapping on particular airplane models. 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
Technify Motors GmbH has also issued Technify Motors SB No. TM TAE 000-0007, Revision 28, dated February 5, 2015; Technify Motors Installation Manual No. IM-02-02, Issue 4, Revision 2, dated January 30, 2015, with Chapter 02-IM-13-02, section 13.8.16, Revision 1, dated November 28, 2014; Technify Motors SB No. SB TMG 601-1007 P1, Revision 3, dated February 5, 2015; and Technify Motors SB No. SB TMG 651-1004 P1, Revision 2, dated February 5, 2015. Diamond Aircraft Industries GmbH (DAI) has issued DAI Mandatory Service Bulletin (MSB) No. 42-109/1, dated February 4, 2015; and DAI MSB No. 42-007/16, dated February 4, 2015. The service information describes procedures for installing a start phase monitoring system and associated specified software mapping.
We estimate that this AD affects 97 engines installed on airplanes of U.S. registry. We also estimate that it will take about 3 hours per engine to comply with this AD. The average labor rate is $85 per hour. For 13 of the engines, required parts cost about $285 per engine. For 84 of the engines, required parts cost about $206 per engine. Based on these figures, we estimate the cost of this AD on U.S. operators to be $45,744.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this AD will not have federalism implications under Executive Order 13132. This AD will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify this AD:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska to the extent that it justifies making a regulatory distinction, and
(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD becomes effective November 27, 2015.
None.
This AD applies to Technify Motors GmbH TAE 125-02-99 (commercial designation CD-135, formerly Centurion 2.0) and TAE 125-02-114 (commercial designation CD-155, formerly Centurion 2.0S) reciprocating engines, with a dual mass flywheel installed.
This AD was prompted by reports of a gearbox drive shaft breaking during starting or restarting of the engine. We are issuing this AD to prevent overload and failure of the gearbox drive shaft, which could lead to failure of the engine, in-flight shutdown, and loss of control of the airplane.
Comply with this AD within the compliance times specified, unless already done.
Within 110 flight hours or at the next scheduled inspection after the effective date of this AD, whichever occurs first, install a start phase monitoring system and software mapping. Use Technify Motors Service Bulletin (SB) No. SB TMG 125-1018 P1, Revision 1, dated February 5, 2015, to do the installation.
After the effective date of this AD, do not install onto any airplane any Technify Motors TAE 125-02-99 or TAE 125-02-114 reciprocating engine that is not equipped with a start phase monitoring system and software mapping.
The Manager, Engine Certification Office, may approve AMOCs for this AD. Use the procedures found in 14 CFR 39.19 to make your request. You may email your request to:
(1) For more information about this AD, contact Robert Green, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7754; fax: 781-238-7199; email:
(2) Refer to MCAI European Aviation Safety Agency AD 2015-0055, dated March 31, 2015, for more information. You may examine the MCAI in the AD docket on the Internet at
(3) Technify Motors SB No. TM TAE 000-0007, Revision 28, dated February 5, 2015; Technify Motors Installation Manual No. IM-02-02, Issue 4, Revision 2, dated January 30, 2015, with Chapter 02-IM-13-02, section 13.8.16, Revision 1, dated November 28, 2014; Technify Motors SB No. SB TMG 601-1007 P1, Revision 3, dated February 5, 2015; and Technify Motors SB No. SB TMG 651-1004 P1, Revision 2, dated February 5, 2015,
(4) Diamond Aircraft Industries GmbH (DAI) MSB No. 42-109/1, dated February 4, 2015; and DAI MSB No. 42-007/16, dated February 4, 2015, which are not incorporated by reference in this AD, can be obtained from Diamond Aircraft Industries GmbH, using the contact information in paragraph (h)(5) of this AD.
(5) For DAI service information identified in this AD, contact Diamond Aircraft Industries GmbH, N. A. Otto-Strasse 5, 2700 Wiener Neustadt, Austria; phone: +43 2622 26700; fax: +43 2622 26700 1369; email:
(6) You may view this service information at the FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA. For information on the availability of this material at the FAA, call 781-238-7125.
(1) The Director of the Federal Register approved the incorporation by reference (IBR) of the service information listed in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.
(2) You must use this service information as applicable to do the actions required by this AD, unless the AD specifies otherwise.
(i) Technify Motors Service Bulletin (SB) No. SB TMG 125-1018 P1, Revision 1, dated February 5, 2015.
(ii) Reserved.
(3) For Technify Motors GmbH service information identified in this AD, contact Technify Motors GmbH, Platanenstrasse 14, D-09356 Sankt Egidien, Germany; phone: +49-37204-696-0; fax: +49-37204-696-55; email:
(4) You may view this service information at FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA. For information on the availability of this material at the FAA, call 781-238-7125.
(5) You may view this service information at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:
Federal Aviation Administration (FAA), DOT.
Final rule.
This action removes Class E airspace at O'Neal Airport, Vincennes, IN. Controlled airspace is no longer needed as the airport was abandoned in 2009 and is being removed from the FAAs database.
Effective 0901 UTC, December 10, 2015. The Director of the Federal Register approves this incorporation by reference action under title 1, Code of Federal Regulations, part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments.
FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed on line at
FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.
Jim Pharmakis, Operations Support Group, Central Service Center, Federal Aviation Administration, Southwest Region, 10101 Hillwood Parkway, Fort Worth, TX 76177; telephone: (817) 222-5855.
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 removes Class E airspace at O'Neal Airport, Vincennes, IN.
During an airspace review, the FAA found that O'Neal Airport, Vincennes, IN, has been abandoned since in 2009, therefore, controlled airspace is removed from the area. Since this eliminates the impact of controlled airspace on users of the National Airspace System, notice and public procedure under 553(b) are unnecessary. Class E airspace designations are published in paragraph 6005 of FAA Order 7400.9Z dated August 6, 2015, and effective September 15, 2014, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.
This document amends FAA Order 7400.9Z, airspace Designations and Reporting Points, dated August 6, 2015, and effective September 15, 2015. FAA Order 7400.9Z is publicly available as listed in the
This amendment to Title 14, Code of Federal Regulations (14 CFR) part 71 removes Class E airspace extending upward from 700 feet above the surface within a 7-mile radius of O'Neal Airport, Vincennes, IN. The airport has been abandoned; therefore, controlled airspace is no longer necessary.
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
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 311a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exist that warrant preparation of an environmental assessment.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120, E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
Federal Aviation Administration (FAA), DOT.
Final rule.
This action establishes Class E airspace at Vidalia, LA. Controlled airspace is necessary to accommodate new Standard Instrument Approach Procedures at Concordia Parish Airport. The FAA is taking this action to enhance the safety and management of Instrument Flight Rules (IFR) operations at the airport.
Effective 0901 UTC, December 10, 2015. The Director of the Federal Register approves this incorporation by reference action under Title 1, Code of Federal Regulations, part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments.
FAA Order 7400.9Z Airspace Designations and Reporting Points and subsequent amendments can be viewed on line at
FAA Order 7400.9, Airspace Designations and Reporting Points is published yearly and effective on September 15.
Rebecca Shelby, Central Service Center, Operations Support Group, Federal Aviation Administration, Southwest Region, 10101 Hillwood Parkway, Fort Worth, TX 76177; telephone: 817-222-5857.
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 establishes controlled airspace at Concordia Parish Airport, Vidalia, LA.
On August 13, 2015, the FAA published in the
Class E airspace designations are published in paragraph 6005 of FAA Order 7400.9Z, dated August 6, 2015, and effective September 15, 2015, which is incorporated by reference in 14 CFR part 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.
This document amends FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, and effective September 15, 2015. FAA Order 7400.9Z is publicly available as listed in the
This action amends Title 14, Code of Federal Regulations (14 CFR), Part 71 by establishing Class E airspace extending upward from 700 feet above the surface within a 6.0-mile radius of Concordia Parish Airport, Vidalia, LA, to accommodate new Standard Instrument Approach Procedures at the airport. This action enhances the safety and management of IFR operations at the airport.
The FAA has determined that this regulation only involves an established
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 311a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exists that warrant preparation of an environmental assessment.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389
That airspace extending upward from 700 feet above the surface within a 7.7-mile radius of Concordia Parish Airport, and within 2 miles each side of the 174° bearing from the airport extending from the 7.7 mile radius to 9 miles south of the airport.
Federal Aviation Administration (FAA), DOT.
Final rule.
This action establishes Class E surface area airspace at Pearson Field, Vancouver, WA, to accommodate existing Standard Instrument Approach Procedures (SIAPS) at the airport. This enhances the safety and management of SIAPs for Instrument Flight Rules (IFR) operations at the airport.
Effective 0901 UTC, December 10, 2015. The Director of the Federal Register approves this incorporation by reference action under Title 1, Code of Federal Regulations, part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments.
FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at
FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.
Steve Haga, Federal Aviation Administration, Operations Support Group, Western Service Center, 1601 Lind Avenue SW., Renton, WA 98057; telephone (425) 203-4563.
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 establishes controlled airspace at Pearson Field, Vancouver, WA.
On August 27, 2015, the FAA published in the
Class E airspace designations are published in paragraph 6002 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 designation listed in this document will be published subsequently in the Order.
This document amends FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, and effective September 15, 2015. FAA Order 7400.9Z is publicly available as listed in the
This amendment to Title 14, Code of Federal Regulations (14 CFR) part 71 establishes Class E surface area airspace, at Pearson Field, Vancouver, WA. A review of the airspace revealed current standard instrument approach procedures not being fully contained within controlled airspace. Class E surface area airspace is established within an area 4.9 miles west, 4 miles east, 2.9 miles north, and 1.8 miles south of Pearson Field.
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current, is non-controversial and unlikely to result in adverse or negative comments. It, therefore: (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a Regulatory Evaluation as the anticipated impact is so minimal. Since this is a routine matter that only affects air traffic procedures and air navigation, it is certified that this rule, when promulgated, does not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA has determined that this action qualifies for categorical exclusion under the National Environmental Policy Act in accordance with FAA Order 1050.1F, “Environmental Impacts: Policies and Procedures,” paragraph 311a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exist that warrant preparation of an environmental assessment.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
That airspace extending upward from the surface bounded by a line beginning at Lat. 45°36′06″ N., Long. 122°46′29″ W.; to Lat. 45°38′27″ N., Long. 122°46′19″ W.; to Lat. 45°40′21″ N., Long. 122°44′08″ W.; to Lat. 45°39′49″ N., Long. 122°33′23″ W.; to Lat. 45°34′51″ N., Long. 122°33′53″ W.; thence to the point of beginning.
Department of State.
Final rule.
The Department of State amends provisions in the Code of Federal Regulations related to the appointment of Foreign Service Officers. The revised rules will be substantially the same as, and will supplement, Department of State guidance currently in the Foreign Affairs Manual, which is also available to the public.
This rule will be effective on November 23, 2015.
Alice Kottmyer, Office of the Legal Adviser, who may be reached at (202) 647-2318.
Pursuant to Section 206 of the Foreign Service Act of 1980 (the Act), codified at 22 U.S.C. 3926, the Secretary of State may prescribe regulations to carry out functions under the Act. The Secretary has done so in the Department's Foreign Affairs Manual (FAM).
The FAM is the formal written document for recording, maintaining, and issuing Department directives, which are written communications establishing and prescribing the organizations, policies, or procedures that provide an official basis of Department operation.
The Foreign Service includes personnel not only from the Department, but U.S. Agency for International Development, and certain offices within the Departments of Commerce and Agriculture, among others. FSOs may be recruited both from current federal personnel (for example, from the civil service) and from the general public. Recruitment from current federal service is covered by the FAM.
The procedures relating to recruitment of FSOs from the general public are covered by rules published in the CFR, in part 11. However, since many of the policies and procedures dealing with the latter appointments are the same as those used to appoint current federal personnel to the Foreign Service, the provisions of part 11 and the FAM must be consistent. Therefore, where part 11 uses the same procedures as the FAM, it refers to the relevant FAM provisions.
Other than a minor amendment in 2002 (
The Department's revision of part 11 is part of its Retrospective Review conducted pursuant to Executive Order 13563.
The revision to part 11 of 22 CFR relates to the Department's organization, procedure, or practice and is not subject to the notice-and-comment procedures of 5 U.S.C. 553(b).
The Department certifies that this rulemaking is not expected to have a significant impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act, 5 U.S.C. 601-612, and Executive Order 13272, section 3(b).
This rulemaking is not a major rule as defined by 5 U.S.C. 804, for purposes of congressional review of agency rulemaking.
Section 202 of the Unfunded Mandates Reform Act of 1995, 2 U.S.C. 1532, generally requires agencies to prepare a statement before proposing or adopting any rule that may result in an annual expenditure of $100 million or more by state, local, or tribal governments, or by the private sector. This rulemaking will not result in any such expenditure nor will it significantly or uniquely affect small governments.
This rulemaking 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. Nor will the rule have federalism implications warranting the application of Executive Orders 12372 and 13132.
Although the Department of State is generally exempt from the provisions of Executive Order 12866, it has reviewed this rulemaking to ensure its consistency with the regulatory philosophy and principles set forth in these Executive Orders, and has determined that the benefits of this rulemaking justify any costs. The Department cannot identify any cost to the public associated with this rulemaking. The Department does not consider this rulemaking to be a significant regulatory action within the scope of section 3 of Executive Order 12866. The Department considers this rule to be part of its Retrospective Review conducted pursuant to Executive Order 13563.
The Department has reviewed this rulemaking in light of sections 3(a) and 3(b)(2) of Executive Order 12988 to eliminate ambiguity, minimize litigation, establish clear legal standards, and reduce burden.
The Department has determined that this rulemaking will not have tribal implications, will not impose substantial direct compliance costs on Indian tribal governments, and will not pre-empt tribal law. Accordingly, the requirements of Section 5 of Executive Order 13175 do not apply to this rulemaking.
The Department of State has determined that this rulemaking does not affect any existing collection of information under the Paperwork Reduction Act, nor does it create new information collections. The Department invites public comment on whether the Foreign Service Office Test Registration (OMB Control Number 1405-0008) burden estimates should be modified as a result of the notification requirements in Section 11.20(d)(2)(i)(B).
Foreign service, Foreign officials, Government employees.
Accordingly, revise 22 CFR part 11 to read as follows:
22 U.S.C. 2651a, 3926, 3941.
(a) The Foreign Affairs Manual (FAM) is the formal written document for recording, maintaining, and issuing Department of State (Department) directives that address personnel and other matters. It is the primary authority for appointment of current Department employees to the Foreign Service. This part is the primary authority for the appointment of non-employees to the Foreign Service. The FAM provides Department procedures and policies that are not repeated in this part. It is an important resource for understanding the provisions of this part.
(b) The two FAM volumes relevant to this part are Volume 3, Personnel, and Volume 16, Medical. FAM provisions are cited by volume followed by chapter or subchapter—for example, Chapter 210 of Volume 16 would be cited 16 FAM 210. All of the relevant FAM provisions are on the Department's public Web site. The links for the relevant FAM provisions are as follows:
(a)
(2)
(3)
(b)
(1)
(2)
(3)
(4)
(c)
(1)
(2)
(3)
(4)
(5)
(i) The Board of Examiners may authorize QEPs to give special consideration in the selection of candidates to certain factors,
(ii) The Board of Examiners may choose to verify accounts given by candidates in their personal narratives.
(d)
(1)
(2)
(B) Candidates must schedule the FSOA within 12 months of receiving their invitation to take the FSOA unless they receive an extension of time. Candidates may request an extension of up to an additional 12 months. Active duty military have unrestricted time to take an FSOA if they notify the Board of Examiners of their active duty status. Failure to take the FSOA within 12 months of the invitation will result in the cancellation of the candidacy, unless the candidate has requested and obtained an extension of eligibility. The candidacy of anyone for whom the scheduling period is extended by the Board due to being outside of the United States will automatically be terminated if the candidate fails to notify his or her registrar of the change in status within three months of returning to the United States. The candidate must schedule an FSOA, but if a candidate fails to appear for a scheduled FSOA, the candidacy is automatically terminated. The Director of the Office of Recruitment, Examination, and Employment in the Bureau of Human Resources, or his/her designee, will consider requests to reschedule on a case-by-case basis if a candidate so requests prior to his/her scheduled FSOA.
(ii)
(iii)
(iv)
(B) Under any other special entry programs created by the Department to meet specific needs of the Foreign Service.
(3)
(4)
(ii) Service as an assessor shall be limited to a maximum of 5 years, unless a further period is specifically authorized by the Board. Normally assessment panels shall be chaired by a career officer of the Foreign Service, trained in personnel testing and evaluation. Determinations of duly constituted panels of assessors are final unless modified by specific action of the Board of Examiners.
(5)
(e)
(f)
(2) [Reserved]
(g)
(h)
(ii) Except for preference eligible individuals, career candidate appointments must be made before the candidate's 60th birthday. Preference eligible individuals must be appointed before their 65th birthday. The maximum age for appointment under this program is based on the requirement that all career candidates must be able to:
(A) Complete at least two full tours of duty, exclusive of orientation and training;
(B) Complete the requisite eligibility period for tenure consideration; and
(C) Complete the requisite eligibility period to receive retirement benefits, prior to reaching the mandatory retirement age of 65 prescribed by the Act.
(iii) A candidate may be certified as eligible for direct appointment to classes FS-6, FS-5 or FS-4 based on established, publicly available, criteria.
(iv) Employees who receive a career candidate appointment,
(2)
(3)
(4)
(i)
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(j)
(a)
(2) Veterans' preference shall apply to the selection and appointment of Foreign Service specialist career candidates. Veterans' preference is an affirmative factor once the candidate has been qualified for the position. As soon as veterans go on the Hiring Register, they may apply for additional points to increase their rank order standing.
(b)
(ii) Candidates who receive a career candidate appointment,
(2)
(i) Complete at least two full tours of duty, exclusive of orientation and training,
(ii) Complete the requisite eligibility period for tenure consideration, and
(iii) Complete the requisite eligibility period to receive retirement benefits, prior to reaching the mandatory retirement age of 65 prescribed by the Act.
(3)
(ii) Based on a job analysis, the Board of Examiners, in coordination with any bureau responsible for the specialty, will establish the knowledge, skills, and abilities required to perform successfully the tasks and duties of Foreign Service specialists in that functional field. Assessors working for the Board of Examiners will screen applications under those approved criteria and select those who meet the requirements to invite to an oral assessment.
(4)
(5)
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Consistent with section 303 of the Act (22 U.S.C. 3943), the Secretary of State may also appoint Civil Service employees and other individuals to the Foreign Service, and, consistent with section 309 of the Act (22 U.S.C. 3949), such appointments may include limited non-career appointments (LNAs). After meeting the job specific requirements, candidates must meet applicable medical, security, and suitability requirements. Limited non-career appointments are covered under 3 FAM 2290.
Coast Guard, DHS.
Notice of deviation from drawbridge regulations.
The Coast Guard has issued a temporary deviation from the operating schedule that governs the Coleman Memorial Bridge (US 17) across the York River, mile 7.0, at Yorktown, VA. This deviation allows the bridge to remain in the closed-to-navigation position to facilitate mechanical repairs to the bridge.
This deviation is effective from 10 p.m. on November 14, 2015, until 7 a.m. on November 22, 2015.
The docket for this deviation, [USCG-2015-0973], is available at
If you have questions on this temporary deviation, call or email Mr. Hal R. Pitts, Bridge Administration Branch Fifth District, Coast Guard; telephone (757) 398-6222, email
The Virginia Department of Transportation, who owns and operates the Coleman Memorial Bridge (US 17), has requested a temporary deviation from the current operating regulations to facilitate mechanical repairs to the movable grating between one of the movable spans and the fixed bridge. The bridge is a swing bridge and has a vertical clearance in the closed position of 60 feet above mean high water.
The current operating schedule is set out in 33 CFR 117.1025. Under this temporary deviation, the bridge will remain in the closed-to-navigation position from 10 p.m. on November 14, 2015, until 7 a.m. on November 15, 2015. If necessary due to inclement weather on November 14, 2015, the bridge will remain in the closed-to-navigation position from 10 p.m. on November 21, 2015, until 7 a.m. on November 22, 2015. The York River is used by a variety of vessels including deep draft ocean-going vessels, U.S. government vessels, small commercial fishing vessels, recreational vessels and tug and barge traffic. The Coast Guard has carefully coordinated the restrictions with U.S. government and commercial waterway users.
Vessels able to pass through the bridge in the closed position may do so at anytime. The bridge will not be able to open for emergencies and there is no alternate route for vessels unable to pass through the bridge in the closed position. The Coast Guard will also inform the users of the waterways through our Local and Broadcast Notice to Mariners of the change in operating schedule for the bridge so that vessels can arrange their transits to minimize any impacts caused by this temporary deviation.
In accordance with 33 CFR 117.35(e), the drawbridge must return to its regular operating schedule immediately at the end of the effective period of this temporary deviation. This deviation from the operating regulations is authorized under 33 CFR 117.35.
Coast Guard, DHS.
Notice of temporary deviation from regulations.
The Coast Guard has issued a temporary deviation from the operating schedule that governs the Burlington Northern Santa Fe Railroad Company (BNSF) Bridge 37.0 across the Snohomish River, mile 3.5 at Marysville, WA. The deviation is necessary to accommodate scheduled bridge rail joint maintenance and replacement. The deviation allows the bridges to remain in the closed-to-navigation position during the maintenance to allow safe movement of work crews.
This deviation is effective from November 1, 2015 through November 15, 2015.
The docket for this deviation, [USCG-2015-0947] is available at
If you have questions on this temporary deviation, call or email the Bridge Administrator, Coast Guard Thirteenth District; telephone 206-220-7234 email
BNSF has requested a temporary deviation from the operating schedule for the BNSF RR Bridge 37.0, mile 3.5, crossing Snohomish River, at Marysville, WA. BNSF requested the BNSF RR Bridge 37.0 remain in the closed-to-navigation position for rail maintenance. This maintenance has been scheduled, and is funded as part of the Cascade Corridor Improvement Project.
The normal operating schedule for this bridge operates in accordance with 33 CFR 117.5 which states it must open promptly on signal at any time, and requires constant attendance by with a drawtender. BNSF RR Bridge 37.0 provides 10 feet of vertical clearance in the closed-to-navigation position.
This deviation allows the BNSF RR Bridge 37.0, at mile 3.5 crossing Snohomish River, to remain in the closed-to-navigation position, and need not open for maritime traffic from 10 a.m. until 4 p.m. from November 1, 2015 through November 15, 2015; except, the bridge will remain in the closed-to-navigation position from 8 a.m. until Midnight on November 10, 2015 and from 8 a.m. until Midnight on November 12, 2015. The bridge shall operate in accordance to 33 CFR part 117, subpart A at all other times.
Vessels able to pass through the bridge in the closed-to-navigation position may do so at anytime. The bridge will be required to open, if needed, for vessels engaged in emergency response operations during this closure period, but any time lost to emergency openings will necessitate a time extension added to the approved dates. Waterway usage on this part of the Snohomish River includes tug and barge to small pleasure craft. No immediate alternate route for vessels to pass is available on this part of the river. The Coast Guard will also inform the users of the waterways through our Local and Broadcast Notices to Mariners of the change in operating schedule for the bridge so that vessels can arrange
In accordance with 33 CFR 117.35(e), the drawbridges must return to their regular operating schedule immediately at the end of the effective period of this temporary deviation. This deviation from the operating regulations is authorized under 33 CFR 117.35.
National Park Service, Interior.
Final rule.
The National Park Service is amending its regulations for sport hunting and trapping in national preserves in Alaska. This rule provides that the National Park Service does not adopt State of Alaska management actions or laws or regulations that authorize taking of wildlife, which are related to predator reduction efforts (as defined in this rule). This rule affirms current State prohibitions on harvest practices by adopting them as federal regulation. The rule also prohibits the following activities that are allowed under State law: Taking any black bear, including cubs and sows with cubs, with artificial light at den sites; taking brown bears and black bears over bait; taking wolves and coyotes during the denning season; harvest of swimming caribou or taking caribou from a motorboat while under power; and using dogs to hunt black bears. The rule also simplifies and updates procedures for closing an area or restricting an activity in National Park Service areas in Alaska; updates obsolete subsistence regulations; prohibits obstructing persons engaged in lawful hunting or trapping; and authorizes the use of native species as bait for fishing.
This rule is effective November 23, 2015.
Andee Sears, Regional Law Enforcement Specialist, Alaska Regional Office, 240 West 5th Ave., Anchorage, AK 99501. Phone (907) 644-3417. Email:
On September 4, 2014, the National Park Service (NPS) published the proposed rule in the
During the first comment period in 2014, the NPS held 17 public hearings in various locations in Alaska. Approximately 168 individuals attended these hearings and approximately 120 participants provided testimony during the formal public comment sessions. During the second comment period, nine public meetings were held in the State. A total of 29 individuals attended the public meetings, and a total of nine attendees spoke during the formal public comment sessions. The NPS also held two statewide government-to-government consultation teleconferences, and offered to consult in person, with tribes. Four comments were received during the statewide government-to-government consultation conference calls and the NPS met with three tribes that requested consultation in person (Allakaket, Tazlina, and Chesh'na (Chistochina)).
The NPS received approximately 70,000 comments on the proposed rule during the public comment period. These included unique comment letters, form letters, and signed petitions. Approximately 65,000 comments were form letters. The NPS also received three petitions with a combined total of approximately 75,000 signatures. Some commenters sent comments by multiple methods. NPS attempted to match such duplicates and count them as one comment. Additionally, many comments were signed by more than one person. NPS counted a letter or petition as a single comment, regardless of the number of signatories.
A summary of comments and NPS responses is provided below in the section entitled “Summary of and Responses to Public Comments.” After considering the public comments and additional review, the NPS made some changes in the final rule from that proposed. These changes are summarized below in the section entitled “Changes from the Proposed Rule.”
In enacting the Alaska National Interest Lands Conservation Act (ANILCA) (16 U.S.C. 410hh-410hh-5; 3101-3233) in 1980, Congress's stated purpose was to establish in Alaska various conservation system units that contain nationally significant values, including units of the National Park System, in order to preserve them “for the benefit, use, education, and inspiration of present and future generations[.]” 16 U.S.C. 3101(a). Included among the express purposes in ANILCA are preservation of wildlife, wilderness values, and natural undisturbed, unaltered ecosystems while allowing for recreational opportunities, including sport hunting. 16 U.S.C. 3101(a)-(b).
The legislative history of ANILCA reinforces the purpose of the National Park System units to maintain natural, undisturbed ecosystems. “Certain units have been selected because they provide undisturbed natural laboratories—among them the Noatak, Charley, and Bremner River watersheds.” Alaska National Interest Lands, Report of the Senate Committee on Energy and Natural Resources, Report No. 96-413 at page 137 [hereafter Senate Report]. Legislative history identifies Gates of the Artic, Denali, Katmai, and Glacier Bay National Parks as “large sanctuaries where fish and wildlife may roam freely, developing their social structures and evolving over long periods of time as nearly as possible without the changes that extensive human activities would cause.” Senate Report, at page 137.
The congressional designation of “national preserves” in Alaska was for the specific and sole purpose of allowing sport hunting and commercial trapping, unlike areas designated as national parks. 126 Cong. Rec. H10549 (Nov. 12, 1980) (Statement of Rep. Udall). 16 U.S.C. 3201 directs that national preserves shall be managed “in the same manner as a national park . . . except that the taking of fish and wildlife for sport purposes and subsistence uses, and trapping shall be allowed in a national preserve[.]” Under ANILCA and as used in this document, the term “subsistence” refers to subsistence activities by rural Alaska residents authorized by Title VIII of ANILCA, which ANILCA identifies as the priority consumptive use of fish and
In addressing wildlife harvest, the legislative history provided “the Secretary shall manage National Park System units in Alaska to assure the optimum functioning of entire ecological systems in undisturbed natural habitats. The standard to be met in regulating the taking of fish and wildlife and trapping, is that the preeminent natural values of the Park System shall be protected in perpetuity, and shall not be jeopardized by human uses.” 126 Cong. Rec. H10549 (Nov. 12, 1980) (Statement of Rep. Udall). This is reflected in the statutory purposes of various national preserves that were established by ANILCA, which include the protection of populations of fish and wildlife, including specific references to predators such as brown/grizzly bears and wolves.
Activities related to taking wildlife remain subject to other federal laws, including the mandate of the NPS Organic Act (54 U.S.C. 100101) “to conserve the scenery, natural and historic objects, and wild life” in units of the National Park System and to provide for visitor enjoyment of the same for this and future generations. Policies implementing the NPS Organic Act require the NPS to protect natural ecosystems and processes, including the natural abundances, diversities, distributions, densities, age-class distributions, populations, habitats, genetics, and behaviors of wildlife. NPS Management Policies 2006 §§ 4.1, 4.4.1, 4.4.1.2, 4.4.2. The legislative history of ANILCA reflects that Congress did not intend to modify the NPS Organic Act or its implementing policies in this respect: “the Committee recognizes that the policies and legal authorities of the managing agencies will determine the nature and degree of management programs affecting ecological relationships, population's dynamics, and manipulations of the components of the ecosystem.” Senate Report, at pages 232-331. NPS policy states that “activities to reduce . . . native species for the purpose of increasing numbers of harvested species (
The State's legal framework for managing wildlife in Alaska is based on sustained yield, which is defined by State statute to mean “the achievement and maintenance in perpetuity of the ability to support a high level of human harvest of game[.]” AS § 16.05.255(k)(5). To that end, the Alaska Board of Game (BOG) is directed to “adopt regulations to provide for intensive management programs to restore the abundance or productivity of identified big game prey populations as necessary to achieve human consumptive use goals[.]” AS § 16.05.255(e). Allowances that manipulate natural systems and processes to achieve these goals, including actions to reduce or increase wildlife populations for harvest, conflict with laws and policies applicable to NPS areas that require preserving natural wildlife populations. See,
This potential for conflict was recognized by the Senate Committee on Energy and Natural Resources prior to the passage of ANILCA, when the Committee stated that “[i]t is contrary to the National Park Service concept to manipulate habitat or populations to achieve maximum utilization of natural resources. Rather, the National Park System concept requires implementation of management policies which strive to maintain natural abundance, behavior, diversity and ecological integrity of native animals as part of their ecosystem, and that concept should be maintained.” Senate Report, at page 171.
In the last several years, the State of Alaska has allowed an increasing number of liberalized methods of hunting and trapping wildlife and extended seasons to increase opportunities to harvest predator species. Predator harvest practices recently authorized on lands in the State, including lands in several national preserves, include:
• Taking any black bear, including cubs and sows with cubs, with artificial light at den sites;
• harvesting brown bears over bait (which often includes dog food, bacon/meat grease, donuts, and other human food sources); and
• taking wolves and coyotes (including pups) during the denning season when their pelts have little trophy, economic, or subsistence value.
These practices are not consistent with the NPS's implementation of ANILCA's authorization of sport hunting and trapping in national preserves. To the extent such practices are intended or reasonably likely to manipulate wildlife populations for harvest purposes or alter natural wildlife behaviors, they are not consistent with NPS management policies implementing the NPS Organic Act or the sections of ANILCA that established the national preserves in Alaska. Additional liberalizations by the State that are inconsistent with NPS management directives, policies, and federal law are anticipated in the future.
16 U.S.C. 3201 of ANILCA provides “within national preserves the Secretary may designate zones where and periods when no hunting, fishing, trapping, or entry may be permitted for reasons of public safety, administration, floral and faunal protection, or public use and enjoyment.” In order to comply with federal law and NPS policy, the NPS has adopted temporary restrictions under 36 CFR 13.40(e) to prevent the application of the above listed predator harvest practices to national preserves in Alaska (see,
In deciding not to treat NPS lands differently from State and other lands, the BOG suggested the NPS was responsible for ensuring that taking wildlife complies with federal laws and policies applicable to NPS areas, and that the NPS could use its own authority to ensure national preserves are managed in a manner consistent with federal law and NPS policy. See,
The scope of this rule is limited—sport hunting and trapping are still allowed throughout national preserves and the vast majority of State hunting regulations are consistent with federal
The rule separates regulations that govern the taking of fish and the taking of wildlife into two sections: 13.40 and 13.42, respectively. The rule makes the following substantive changes to existing NPS regulations:
(1) In accordance with NPS policies, taking wildlife, hunting or trapping activities, or management actions involving predator reduction efforts with the intent or potential to alter or manipulate natural predator-prey dynamics and associated natural ecological processes to increase harvest of ungulates by humans are not allowed on NPS-managed lands. It also explains how the NPS will notify the public of specific activities that are not consistent with this section.
(2) Affirms current State prohibitions on harvest practices by adopting them as federal regulation, and also maintains historical prohibitions on certain practices that the State has recently authorized for sport hunting of predators: (i) Taking any black bear, including cubs and sows with cubs, with artificial light at den sites; (ii) taking brown bears over bait; and (iii) taking wolves and coyotes during the denning season. The rule also eliminates exceptions to practices generally prohibited under State of Alaska law, thereby prohibiting: Taking caribou that are swimming, or from a motorboat that is under power, in two game management units (GMU); baiting black bears; and using dogs to hunt black bears.
(3) Prohibits intentionally obstructing or hindering persons actively engaged in lawful hunting or trapping.
(4) Updates and simplifies procedures for implementing closures or restrictions in park areas, including taking fish and wildlife for sport purposes.
(5) Updates NPS regulations to reflect federal assumption of the management of subsistence hunting and fishing under Title VIII of ANILCA from the State in the 1990s.
(6) Allows the use of native species as bait, commonly salmon eggs, for fishing in accordance with applicable federal and non-conflicting State law. This supersedes for park areas in Alaska the National Park System-wide prohibition on using certain types of bait in 36 CFR 2.3(d)(2).
Activities or management actions involving predator reduction efforts with the intent or potential to alter or manipulate natural ecosystems or processes (including natural predator/prey dynamics, distributions, densities, age-class distributions, populations, genetics, or behavior of a species) are inconsistent with the laws and policies applicable to NPS areas. The rule clarifies in regulation that these activities are not allowed on NPS lands in Alaska. Under this rule, the Regional Director will compile a list updated at least annually of activities prohibited by this section of the rule. Notice will be provided in accordance with 36 CFR 13.50(f) of this rule.
The rule codifies for national preserves current State prohibitions on harvest practices, and also maintains historical prohibitions on certain sport hunting practices that have been recently authorized by the State for taking predators. It also eliminates exceptions (as applied to national preserves) under State laws that authorize sport hunters to take swimming caribou, to take caribou from motorboats under power, to take black bears over bait, and to use dogs to hunt black bears. The elements of the rule that are described in this paragraph will not be implemented until January 1, 2016, to avoid any potential confusion that may arise from issuing this rule during the 2015 hunting seasons. Delaying the implementation of these provisions will give the general public and other stakeholders sufficient time to understand the new rules before the 2016 hunting seasons begin.
The rule prohibits the intentional obstruction or hindrance of another person's lawful hunting or trapping activities. This includes (i) placing oneself in a location in which human presence may alter the behavior of the game that another person is attempting to take or alter the imminent feasibility of taking game by another person; or (ii) creating a visual, aural, olfactory, or physical stimulus in order to alter the behavior of the game that another person is attempting to take. These actions are prohibited by State law, but this law is not adopted under the regulations for national preserves, because it does not directly regulate hunting and trapping. This rule directly codifies these prohibitions into the NPS regulations, to prevent the frustration of lawful hunting and trapping in national preserves.
The rule updates and simplies the procedures for implementing closures and restrictions on certain activities in NPS areas in Alaska. These changes will make the procedures in Alaska more consistent with other NPS units outside of Alaska and with Alaska State Parks. The rule clarifies that Superintendents must use the procedures in § 13.50 to implement any closure or restriction in NPS areas in Alaska. This eliminates potential confusion about whether the procedures in § 13.50 apply only when they are referenced in a separate regulation in part 13 (currently found in the regulations for weapons, camping, and taking fish and wildlife), or whether they apply to all closures and restrictions in Alaska.
The rule requires rulemaking for nonemergency closures or restrictions if the closures or restrictions (or the termination or relaxation of them) are of a nature, magnitude and duration that will result in a significant alteration in the public use pattern of the area, adversely affect the area's natural, aesthetic, scenic or cultural values, or require a long-term or significant modification in the resource management objectives of the area. These rulemaking criteria are modeled after the the criteria that apply to closures and restrictions in Alaska State Parks (11 AAC 12.335), which are also similar to the criteria in 36 CFR 1.5(b) that apply to NPS areas outside of Alaska. Emergency closures and restrictions are limited to the duration of the emergency.
Before a nonemergency closure or restriction can be implemented, the NPS must issue a written determination explaining the basis of the closure or restriction. The NPS will also compile in writing a list, updated annually, of all closures and restrictions (
With respect to nonemergency restrictions on taking of fish and wildlife in national preserves, the final rule requires an opportunity for public comment, including a public meeting near the affected NPS unit, before the action is taken. This rule recognizes that, although the internet has become
The following table summarizes the changes from the proposed rule regarding procedures to implement closures or restrictions in § 13.50:
The rule updates the subsistence provisions in NPS regulations (36 CFR 13.470, 13.480, and 13.490) to reflect the federal government's assumption of the management and regulation of subsistence take of fish and wildlife under ANILCA and the transfer of subsistence management under Title VIII from the State to the Federal Subsistence Board. The rule makes other non-substantive, editorial changes to the language in 36 CFR 13.490 to streamline, clarify, and better organize this section.
NPS regulations generally prohibit the use of many forms of bait for fishing to help protect against the spread of nonnative species. Fish eggs from native species (usually salmon), are commonly used for fishing in Alaska. This rule allows the use of local native species as bait for fishing.
This section explains some of the principal elements of the rule in a question and answer format.
The rule responds to State hunting regulations that authorize wildlife harvest practices that conflict with ANILCA's authorization for sport hunting, the statutory purposes for which national preserves were established, and the NPS Organic Act as implemented by the NPS. These include liberalized predator harvest seasons, bear baiting, and the harvest of caribou while swimming. National park areas are managed for natural ecosystems and processes, including wildlife populations. The NPS legal and policy framework prohibits reducing native predators for the purpose of increasing numbers of harvested species.
As discussed above, the rule also responds to a number of other regulatory needs, by updating and streamlining closure procedures, updating subsistence provisions to reflect the program's actual management, prohibiting interference with lawful hunting consistent with State law, and allowing use of native species as bait for fishing.
No.
No. This rule restricts certain methods of harvest currently allowed on national preserves by the State of Alaska under its general hunting regulations. These include the taking of any black bear, including cubs and sows with cubs, with artificial light at den sites, taking
Title 36 of the Code of Federal Regulations (CFR) applies to sport hunting and trapping in national preserves. State harvest laws and regulations (Alaska Statute Title 16 and Alaska Administrative Code Title 5 AAC) that are consistent with 36 CFR also apply on national preserves. ANILCA Title VIII subsistence harvest of fish and wildlife by Federally-qualified rural residents is authorized in national preserves in Alaska under 36 CFR part 13 and 50 CFR part 100. Please contact the park chief ranger for additional information or assistance.
Yes. State hunting regulations apply to national preserves except when in conflict with federal regulation. Please contact the park chief ranger for additional information or assistance.
Yes. Consistent with NPS Management Policies 2006, the NPS Organic Act, and the statutory purposes for which national preserves were established, this rule prohibits predator reduction activities on national preserves that have the intent or potential to alter or manipulate natural predator-prey dynamics and associated natural ecological processes to increase harvest of ungulates by humans.
The NPS Organic Act authorizes the NPS to promulgate regulations that are necessary and proper for the use and management of National Park System units, including national preserves in Alaska, for the purpose of conserving the wild life and providing for the enjoyment of the wild life in such manner and by such means as will leave them unimpaired for the enjoyment of future generations. 54 U.S.C. 100101(a) and 100751. ANILCA authorizes the Secretary of the Interior, acting through the NPS, to promulgate regulations prescribing restrictions relating to hunting, fishing, or trapping for reasons of public safety, administration, floral and faunal protection, or public use and enjoyment. 16 U.S.C. 3201 and 3202.
The Regional Director will compile a list updated at least annually of State laws and regulations that are not adopted in national preserves. This list will be posted at
Title VIII of ANILCA limits subsistence activities to local rural residents. This rule does not restrict federally-qualified subsistence users who are hunting in accordance with federal subsistence regulations. But those persons living in nonrural areas (who therefore are not federally-qualified subsistence users) must comply with the restrictions in this rule. For example, only federally qualified subsistence users hunting under federal subsistence regulations will be able to take swimming caribou within national preserves, for all others this practice will now be prohibited in national preserves.
Hunting in national preserves is different than on State (or private) lands because NPS regulations also apply and govern in the event of a conflict with State law or regulation. However, harvest opportunities and practices in national preserves vary little from practices allowed under State law, except for some very specific circumstances for which where the NPS has issued regulations. For example, same-day airborne hunting of big game animals, arctic fox, red fox, and lynx has not been allowed on NPS lands since 1995. This rule adds several additional NPS regulations prohibiting the following harvest practices that are allowed under State law: (1) Taking any black bear, including cubs and sows with cubs, with artificial light at den sites, (2) taking brown bears and black bears over bait, (3) taking wolves and coyotes from May 1 through August 9, (4) harvest of swimming caribou and harvest of caribou from a moving motorboat by those other than local rural residents in those portions of Noatak, Gates of the Arctic, and Bering Land Bridge Preserves that are within GMUs 23 and 26, and (5) using dogs to hunt black bears.
The NPS proposed prohibiting the harvest of brown bears over bait to avoid public safety issues, to avoid food-conditioning bears and other species, and to maintain natural bear behavior as required by NPS law and policy. Other land and wildlife management agencies strive to eliminate the feeding of bears through individual and collective educational efforts due to the increased likelihood that food-conditioned bears will be killed by agency personnel or the public in defense of life or property. Food-conditioned bears are also believed more likely to cause human injury. Baiting tends to occur in accessible areas used by multiple user groups, which contributes to the public safety concerns associated with baiting. The concerns presented with taking brown bears over bait also apply to black bear baiting. After reviewing public comment, the final rule prohibits taking both black bears and brown bears over bait in national preserves.
Taking swimming big game is already generally prohibited by State law, but there are exceptions in State law for the take of swimming caribou in GMUs 23 and 26, which include portions of Noatak, Bering Land Bridge, and Gates of the Arctic National Preserves. This method of harvest remains available to federally qualified subsistence users in their pursuit of food. However, as is further explained below, this method is one of those that NPS has found is not consistent with ANILCA's authorization for sport hunting in national preserves.
Yes. This rule allows federally qualified subsistence users to use native species as bait for fishing in accordance with federal subsistence regulations.
The procedures in 36 CFR 13.50 apply to all closures and restrictions in NPS units in Alaska, unless there are more specific procedures stated elsewhere in law or regulation. For example, the following regulations have specific procedures:
• Unattended or abandoned property, 36 CFR 13.45
• Use of snowmobiles, motorboats, dog teams, and other means of surface transportation traditionally employed by local rural residents engaged in subsistence uses, 36 CFR 13.460
• Subsistence use of timber and plant material, 36 CFR 13.485
• Closure to subsistence uses of fish and wildlife, 36 CFR 13.490
Any nonemergency closure or restriction, or the termination or relaxation of such, which is of a nature, magnitude, and duration that will result in a significant alteration in the public use pattern of the area; adversely affect the area's natural, aesthetic, scenic, or cultural values; or require a long-term modification in the resource management objectives of the area.
Public hearings near the affected vicinity are required before restricting: (1) Subsistence harvest of fish or wildlife under Title VIII of ANILCA or (2) access authorized under 16 U.S.C. 3170 (a) of ANILCA. There is no statutory requirement for a public hearing for other types of closures or restrictions.
The proposed rule included a requirement to provide an opportunity for public comment on potential restrictions to taking fish or wildlife. Public comment may include written comments, a public meeting, a public hearing, or a combination thereof. Based upon public comment and to be more consistent with the practices of the BOG and the Federal Subsistence Board, the NPS modified the proposed rule to provide that the opportunity for comment must include at least one public meeting near the affected NPS unit in nonemergency situations. This is a change from the existing regulations, which require a public hearing. Requiring a “meeting” instead of a “hearing” provides more flexibility on how the event is structured. During the public hearings conducted in 2014, the NPS received feedback that some local communities prefer a less formal approach and more opportunities for dialog with NPS managers. The NPS believes the term “meeting” more appropriately describes this type of informational exchange. The NPS also believes the term public meeting is broad enough to include a public hearing if that is more appropriate for the area.
Information about closures and restrictions is posted on each park's Web site at
The NPS deleted the provisions adopting non-conflicting State law because the State no longer manages subsistence harvest under Title VIII of ANILCA. Subsistence harvest of fish and wildlife on federal public lands is generally regulated by the Federal Subsistence Board.
Yes, except in the case of emergencies.
Yes, the NPS is required to consult with tribes if an NPS action would have a substantial direct effect on federally recognized Indian tribes. Consultation with ANCSA Native Corporations is required if an NPS action would have a substantial direct effect on ANCSA Native Corporation lands, waters, or interests.
While this kind of consultation is not required by law, the NPS regards the input from these advisory and other groups as invaluable. The NPS encourages these groups to engage with park managers on topics of interest. The NPS also invites and encourages these committees and groups to provide input on decisions affecting public use of NPS managed lands as outlined in this final rule.
A summary of substantive comments and NPS responses is provided below followed by a table that sets out changes we have made to the proposed rule based on the analysis of the comments and other considerations.
Executive Order 12866 requires federal agencies to “seek views of appropriate State, local, and tribal governments before imposing regulatory requirements that might significantly or uniquely affect those governmental entities.” Sec. 1(b)(9). As discussed below, the Office of Management and Budget determined this rule is not a significant regulatory action subject to this requirement. Regardless, the NPS invited the views of State, local, and tribal governments before publishing this final rule, and also complied with its responsibilities under section 4 of the Executive Order by including the proposed rule in the Unified Regulatory Agenda that was published by the Office of Management and Budget on reginfo.gov.
The NPS signed and implemented the Master Memorandum of Understanding (MMOU) with the ADF&G in 1982. The MMOU states that the ADF&G will manage wildlife on NPS managed lands for natural species diversity and natural process. The NPS agreed to recognize ADF&G as having the primary responsibility to manage wildlife on lands in the State and utilize the State's regulatory process to the maximum extent possible. Both agencies agreed to coordinate planning to minimize conflicts from differing legal mandates and consult with each other when developing regulations. The NPS continues to recognize the State as having primary responsibility to manage fish and wildlife on lands in the State. However, the State's responsibility is not exclusive and it does not preclude federal regulation of wildlife on federal public lands, as is well-established in the courts and specifically stated in ANILCA. The NPS also attempted to utilize the State regulatory process to notify the BOG when proposals created a conflict with NPS laws, regulations, and policies, years before the publication of the proposed rule. During this time NPS requested that the conflicts be resolved, as a first resort, through the State regulatory process. Only after conflicts could not be resolved through that process, and the BOG suggested the NPS could use its own authority to meet is mandates for managing wildlife, did the NPS consider modifications to federal regulations to resolve the conflicts.
During the comment periods for the proposed rule, the NPS held 26 public hearings in Alaska in an effort to solicit the opinions and comments of Alaskans. The NPS has considered all relevant comments it received on the proposed rule, including those from rural Alaskans and those delivered at public meetings. The NPS considers each comment based upon its substantive content, and does not give greater weight to any comment based upon the residence of the commenter. This is also consistent with the statutory purpose for establishing the national preserves in Alaska for the benefit, use, education, and inspiration of present and future generations of all Americans.
After considering public comments and after additional review, the NPS made certain changes to the proposed rule, which are described in the section below entitled “Changes from the Proposed Rule.” The changes are a logical outgrowth of the proposed rule, and were reasonably foreseeable by the public when the proposed rule was published. For example, the NPS specifically requested comment on taking black bears over bait in the proposed rule. This notified the public that the proposed rule could change with respect to this issue after consideration of public comment. Other changes to the proposed rule, such as requiring a public meeting before adopting a closure or restriction for taking wildlife, are consistent with the existing regulations at 36 CFR 13.50.
The NPS believes that the standard in the rule is a workable and limited standard that satisfies our legal and policy framework and does not include all actions that result in the harvest of wildlife. This rule provides that the NPS does not adopt State management actions or laws or regulations that authorize taking of wildlife, which are related to predator reduction efforts, meaning that they have the intent or potential to alter or manipulate natural predator-prey dynamics and associated natural ecological processes, in order to increase harvest of ungulates by humans. The NPS acknowledges that the public would benefit from greater clarity as to exactly which State laws and regulations are not adopted by the NPS. As a result, the rule requires the Regional Director to publish at least annually a list of all such laws and regulations not adopted in national preserves.
As explained in the background section of this rule, NPS management policies prohibit the manipulation of wildlife populations, and require the NPS to protect natural abundances, distributions, densities, and populations of wildlife. This rule does not favor predators over ungulates, which would also violate NPS management policies. The rule is primarily focused on the take of predators because the allowances implemented by the State target predators, not ungulates. Even in these circumstances, the rule is consistent with NPS policy to allow for the fluctuation of natural populations of all species in national preserves, by prohibiting the purposeful decrease of predator populations to achieve (or attempt) an increase of ungulate populations to benefit hunters.
The NPS acknowledges that some rural residents eligible to harvest wildlife under federal subsistence regulations in NPS units also harvest wildlife under State regulations in national preserves, particularly when the State methods, seasons, and bag limits are more liberal. To the extent that this harvest does not conflict with NPS regulations applicable to sport hunting, these opportunities are preserved. Any changes to federal subsistence regulations should be proposed to the Federal Subsistence Board.
The NPS also recognizes that some practices that are being prohibited for “sport” hunters may be appropriate for subsistence users. An example of this is taking swimming caribou. On NPS lands, the take of swimming caribou for subsistence is allowed in accordance with federal subsistence regulations, but it is not appropriate as a “sport” hunting practice on waters within national preserves.
Similarly, 16 U.S.C. 3125(3) does not apply to this rule. That provision provides that “[n]othing in this title shall be construed as . . . authorizing a restriction on the taking of fish and wildlife for nonsubsistence uses . . . unless necessary for the conservation of healthy populations of fish and wildlife . . . to continue subsistence uses of such populations [.]” The phrase “this
ANILCA allows the Secretary of the Interior (acting through the NPS) to restrict sport hunting and trapping in national preserves after consultation with the State of Alaska, and does not diminish the authority of the Secretary of the Interior over the management of public lands. See the Background section of this final rule for more information about NPS authority to promulgate this rule. The NPS believes that compiling and annually updating a list of the activities prohibited by paragraph (f) is consistent with the statutory authority provided to the NPS for the management of national preserves.
Because the concerns presented by taking brown bears over bait also apply to black bear baiting, the NPS requested public comment on whether taking black bears over bait should be allowed to continue on national preserves. After reviewing public comment, the NPS has decided to prohibit taking black bears over bait in national preserves. This decision is consistent with State regulations applicable to Denali State Park, where taking of wildlife is authorized but taking black bears over bait is prohibited (see 2014-2015 Alaska Hunting Regulations, p. 27 and 78 and 5 AAC 92.044 for game management units where the practice is authorized).
Bait stations tend to be located in accessible areas due to the infrastructure (typically a 55 gallon drum) and quantity (including weight) of bait used to engage in this activity and the frequency with which the stations must be replenished. Because of the accessibility of these areas, they are typically used by multiple user groups, which contributes to the public safety concerns associated with baiting. Although there are State regulations that prohibit bait stations within a certain distance of structures (cabins/residences), roads, and trails, these distances lack biological significance relative to bears, whose home ranges can include tens to hundreds of square miles.
The NPS recognizes that the number of bears harvested over bait in national preserves may not be large. However, this provision is not based on how many bears are harvested or whether that harvest would impact bear population levels. It is based on the legal and policy framework that governs national preserves and calls for maintaining natural ecosystems and processes and minimizing safety concerns presented by food-conditioned bears.
Upon review of comments and considering the practices of the Federal Subsistence Board, the NPS agrees with the recommendation to retain the language providing for consultation with the State prior to the NPS implementing closures to subsistence take of fish and wildlife. Because harvest is regulated by the Federal Subsistence Board, the NPS has modified the proposed rule to also include consultation with the Federal Subsistence Board.
Finally, for consistency with 36 CFR 13.50, which was modified based upon comments (addressed below), the rule has been modified to specify that public hearings will be held near the affected park unit (rather than the “affected vicinity”) prior to implementing the management action in nonemergency situations.
While commenters referred generally to the proposed changes as being inconsistent with ANILCA, the only provision cited was 16 U.S.C. 3202. That section contains general savings provisions preserving the Secretary's authority to manage public lands and preserving the State's non-conflicting authority to manage fish and wildlife on those lands. Nothing in that section is specifically relevant to the closure and restriction provisions of 36 CFR 13.50; accordingly the NPS finds no conflict between ANILCA and these procedural updates.
With regard to the duration of emergency closures, the NPS rule is more consistent with the practice of other agencies and NPS regulations that apply outside of Alaska. The existing regulations limit emergency closures to 30 days without extension. Federal subsistence regulations regarding subsistence harvest of fish and wildlife provide for emergency closures of up to 60 days and allow for extensions. National Park System-wide regulations and Alaska State Parks regulations do not provide a time limit on emergency closures. 36 CFR 1.5, 11 AAC 12.355. With respect to restrictions on taking fish and wildlife for sport purposes in national preserves, the NPS adopts the 60-day timeframe and allows for extensions—after consultation with the State and public comment (including a public meeting)—if the emergency persists. The NPS believes the public will benefit from this consistency with respect to emergency closures or restrictions on taking of fish or wildlife. Other emergency actions will have no explicit expiration date and may exist until the emergency is resolved. This is consistent with regulations for NPS units located outside of Alaska and for Alaska State Parks.
The NPS agrees that input from advisory groups, NPS Subsistence Resource Commissions, and others is important and valuable and the NPS encourages these groups to engage with the park superintendents on topics of interest. The NPS, however, does not agree that the provisions of 16 U.S.C. 3118(b) apply as broadly as suggested. Under 16 U.S.C. 3118, Subsistence Resource Commissions are established for areas designated as national parks and monuments (not national preserves) to provide subsistence hunting program recommendations. ANILCA further provides that a subsistence hunting program recommendation for national parks and monuments must be implemented unless it “violates recognized principles of wildlife conservation, threatens the conservation of healthy population of wildlife . . . is contrary to the purposes for which the park or park monument is established, or would be detrimental to the satisfaction of subsistence needs of local residents.” While Subsistence Resource Commissions provide valuable input on multiple topics that affect national parks, monuments, and national preserves, the Subsistence Resource Commission's statutory charge is specific to Title VIII subsistence hunting program recommendations in national parks and monuments. This rule does not restrict Title VIII subsistence and applies only to sport harvest on national preserves. Therefore 16 U.S.C. 3118(b) does not apply.
Under the existing regulations, the superintendent must consider factors including public health and safety, resource protection, protection of cultural or scientific values, subsistence uses, conservation of endangered or threatened species, and other management considerations in determining whether to adopt closures or restrictions on an emergency basis. These factors appear elsewhere in 36 CFR part 13 (
In the final rule, the NPS has decided that adding a requirement that the superintendent consider protecting “naturally functioning ecosystems” is unnecessary because this consideration is encompassed by the existing
After taking the public comments into consideration and after additional review, the NPS made the following substantive changes in the final rule:
Executive Order 12866 provides that the Office of Information and Regulatory Affairs (OIRA) in the Office of Management and Budget will review all significant rules. OIRA has determined that this rule is not significant.
Executive Order 13563 reaffirms the principles of Executive Order 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. Executive Order 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 rule in a manner consistent with these requirements.
This 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
This rule is not a major rule under 5 U.S.C. 804(2), the SBREFA. This rule:
a. Does not have an annual effect on the economy of $100 million or more.
b. Will not cause a major increase in costs or prices for consumers, individual industries, federal, state, or local government agencies, or geographic regions
c. Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S. based enterprises to compete with foreign-based enterprises.
This rule does not impose an unfunded mandate on state, local, or tribal governments or the private sector of more than $100 million per year. The rule does not have a significant or unique effect on state, local or tribal governments or the private sector. A statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531
This rule does not effect a taking of private property or otherwise have taking implications under Executive Order 12630. A takings implication assessment is not required.
Under the criteria in section 1 of Executive Order 13132, this rule does not have sufficient federalism implications to warrant the preparation of a Federalism summary impact statement. The rule's effect is limited to federal lands managed by the NPS in Alaska and it will not have a substantial direct effect on state and local government in Alaska. A Federalism summary impact statement is not required.
This rule complies with the requirements of Executive Order 12988. Specifically, this rule:
(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.
The Department of the Interior strives to strengthen its government-to-government relationship with Indian Tribes through a commitment to consultation with Indian Tribes and recognition of their right to self-governance and tribal sovereignty. We have evaluated this rule under the criteria in Executive Order 13175 and under the Department's tribal consultation and Alaska Native Claims Settlement Act (ANCSA) Native Corporation policies and have determined that tribal consultation is not required because the rule will have no substantial direct effect on federally recognized Indian tribes. While the NPS has determined the rule will have no substantial direct effect on federally recognized Indian tribes or ANCSA Native Corporation lands, water areas, or resources, the NPS consulted with Alaska Native tribes and Alaska Native Corporations on the proposed rule, as discussed above.
This rule does not contain information collection requirements, and a submission to the Office of Management and Budget under the Paperwork Reduction Act 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.
The NPS has analyzed this rule in accordance with the criteria of the National Environmental Policy Act (NEPA) and 516 DM. We prepared an environmental assessment entitled “Wildlife Harvest On National Park System Preserves In Alaska” (EA) to determine whether this rule will have a significant impact on the quality of the human environment. This rule does not constitute a major Federal action significantly affecting the quality of the human environment, and an environmental impact statement is not required, because we reached a Finding of No Signficant Impact (FONSI). The EA and FONSI are available online at
This rule is not a significant energy action under the definition in Executive Order 13211. A Statement of Energy Effects is not required.
The primary authors of this regulation are Jay Calhoun, Regulations Program Specialist, National Park Service, Division of Jurisdiction, Regulations, and Special Park Uses; Philip Hooge, Denali National Park and Preserve; Barbara Cellarius, Wrangell-St. Elias National Park and Preserve; and Guy Adema, Debora Cooper, Joel Hard, Grant Hilderbrand, Brooke Merrell, Bud Rice, and Andee Sears of the Alaska Regional Office, National Park Service.
Alaska, National Parks, Reporting and recordkeeping requirements.
In consideration of the foregoing, the National Park Service amends 36 CFR part 13 as set forth below:
16 U.S.C. 3124; 54 U.S.C. 100101, 100751, 320102; Sec. 13.1204 also issued under Sec. 1035, Pub. L. 104-333, 110 Stat. 4240.
(1) Parts of legally taken wildlife or fish that are not required to be salvaged if the parts are not moved from the kill site; or
(2) Wildlife or fish that died of natural causes, if not moved from the location where it was found.
(d)
(e)
(a) Hunting and trapping are allowed in national preserves in accordance with applicable Federal and non-conflicting State law and regulation.
(b) Violating a provision of either Federal or non-conflicting State law or regulation is prohibited.
(c) Engaging in trapping activities as the employee of another person is prohibited.
(d) It shall be unlawful for a person having been airborne to use a firearm or any other weapon to take or assist in taking any species of bear, caribou, Sitka black-tailed deer, elk, coyote, arctic and red fox, mountain goat, moose, Dall sheep, lynx, bison, musk ox, wolf and wolverine until after 3 a.m. on the day following the day in which the flying occurred. This prohibition does not apply to flights on regularly scheduled commercial airlines between regularly maintained public airports.
(e) Persons transporting wildlife through park areas must identify themselves and the location where the wildlife was taken when requested by NPS law enforcement personnel.
(f) State of Alaska management actions or laws or regulations that authorize taking of wildlife are not adopted in park areas if they are related to predator reduction efforts. Predator reduction efforts are those with the intent or potential to alter or manipulate natural predator-prey dynamics and associated natural ecological processes, in order to increase harvest of ungulates by humans.
(1) The Regional Director will compile a list updated at least annually of State laws and regulations not adopted under this paragraph (f).
(2) Taking of wildlife, hunting or trapping activities, or management actions identified in this paragraph (f) are prohibited. Notice of activities prohibited under this paragraph (f)(2) will be provided in accordance with § 13.50(f).
(g) This paragraph applies to the taking of wildlife in park areas administered as national preserves except for subsistence uses by local rural residents pursuant to applicable Federal law and regulation. As of January 1, 2016, the following are prohibited:
(h) The Superintendent may prohibit or restrict the non-subsistence taking of wildlife in accordance with the provisions of § 13.50.
(i) A person may not intentionally obstruct or hinder another person's lawful hunting or trapping by:
(1) Placing oneself in a location in which human presence may alter the behavior of the game that another person is attempting to take or the imminent feasibility of taking game by another person; or
(2) Creating a visual, aural, olfactory, or physical stimulus in order to alter the behavior of the game that another person is attempting to take.
(a)
(b)
(c)
(d)
(e)
(2) Emergency closures or restrictions may not exceed a period of 60 days and may not be extended without following the nonemergency procedures of this section.
(f)
(1) Publication in a newspaper of general circulation in the State or in local newspapers;
(2) Use of electronic media, such as the internet and email lists;
(3) Radio broadcast; or
(4) Posting of signs in the local vicinity.
(g) Violating a closure or restriction is prohibited.
Fish may be taken by local rural residents for subsistence uses in park areas where subsistence uses are allowed in compliance with applicable Federal law and regulation, including the provisions of §§ 2.3 and 13.40 of this chapter. Local rural residents in park areas where subsistence uses are allowed may fish with a net, seine, trap, or spear; or use native species as bait, where permitted by applicable Federal law and regulation.
Local rural residents may hunt and trap wildlife for subsistence uses in park areas where subsistence uses are allowed in compliance with this chapter and 50 CFR part 100.
(a) The Superintendent may temporarily restrict a subsistence activity or close all or part of a park area to subsistence uses of a fish or wildlife population after consultation with the State and the Federal Subsistence Board in accordance with the provisions of this section. The Superintendent may make a temporary closure or restriction notwithstanding any other provision of this part, and only if the following conditions are met:
(1) The restriction or closure must be necessary for reasons of public safety, administration, or to ensure the continued viability of the fish or wildlife population;
(2) Except in emergencies, the Superintendent must provide public notice and hold a public hearing near the affected NPS unit;
(3) The restriction or closure may last only so long as reasonably necessary to achieve the purposes of the closure.
Environmental Protection Agency (EPA).
Final rule.
The Environmental Protection Agency (EPA) is finalizing approval of the State of Florida's March 10, 2015, State Implementation Plan (SIP) revision, submitted by the Florida Department of Environmental Protection (FDEP). This submittal fulfills Florida's commitment to EPA to provide a regional haze SIP revision with a Best Available Retrofit Technology (BART) nitrogen oxides (NOx) emissions limit for Unit 1 at the Lakeland Electric—C.D. McIntosh Power Plant (McIntosh) reflecting best operating practices for good combustion. States are required to address the BART provisions of the Clean Air Act (CAA or Act) and EPA's
This rule is effective November 23, 2015.
EPA has established a docket for this action under Docket Identification No. EPA-R04-OAR-2015-0337. All documents in the docket are listed on the
Michele Notarianni, Air Regulatory Management Section, Air Planning and Implementation Branch, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, Region 4, 61 Forsyth Street SW., Atlanta, Georgia 30303-8960. Ms. Notarianni can be reached by phone at (404) 562-9031 or via electronic mail at
On December 10, 2012, EPA proposed to approve the BART and reasonable progress determinations for a number of EGUs in Florida as part of Florida's regional haze SIP.
To fulfill its commitment in accordance with the July 30, 2013 letter, the State of Florida submitted a SIP revision dated March 10, 2015, revising the State's regional haze SIP to include a NOx BART emissions limit for McIntosh Unit 1 and a construction permit (FDEP Permit No. 1050004-034-AC) dated April 30, 2014, for Unit 1 containing this limit. The permit contains supporting conditions (
In a notice of proposed rulemaking (NPR) published on August 20, 2015, EPA proposed to approve Florida's March 10, 2015, regional haze SIP revision fulfilling the State's July 20, 2013, commitment to provide EPA with a SIP revision containing a NOx BART emissions limit for McIntosh Unit 1 reflecting best operating practices for good combustion and conditions to modify the title V permit to incorporate this limit.
EPA is finalizing approval of the State of Florida's March 10, 2015, SIP revision and revising the regional haze SIP to include the NOx BART emissions limit for Unit 1 and the April 30, 2014, construction permit containing this limit. EPA is approving these changes to the Florida SIP because the submission meets the applicable regional haze requirements as set forth in the CAA and in EPA's regional haze regulations and the applicable requirements of section 110 of the CAA.
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations.
• Is not a significant regulatory action subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).
The SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), nor will it impose substantial direct costs on tribal governments or preempt tribal law.
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by December 22, 2015. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements.
Environmental protection, Air pollution control, Carbon monoxide, Incorporation by reference, Intergovernmental relations, Lead, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides, Volatile organic compounds.
40 CFR part 52 is amended as follows:
42.U.S.C. 7401
(e) * * *
Environmental Protection Agency.
Direct final rule.
The Environmental Protection Agency (EPA) is approving into Oregon's State Implementation Plan (SIP) a submittal from the Oregon Department of Environmental Quality (ODEQ) dated July 7, 2014, containing revisions to the Lane Regional Air Protection Agency's (LRAPA) open burning rules adopted on March 14, 2008. The revised LRAPA open burning rules make clarifications and provide for additional controls of open burning activities in Lane County, would reduce particulate emissions in Lane County, and would strengthen Oregon's SIP. The EPA is also approving a submittal from the ODEQ dated June 30, 2014, to update Oregon Administrative Rules (OAR) that relate to procedures in contested cases (appeals), enforcement procedures, and civil penalties. The EPA is approving most of the submitted provisions because the revisions clarify and strengthen the SIP and are consistent with the Clean Air Act (CAA). The EPA is not approving certain provisions of the submitted rules that do not relate to the requirements for SIPs under section 110 of the CAA. Finally, the EPA is correcting the SIP pursuant to the authority of section 110(k)(6) of the CAA to remove certain provisions previously approved by the EPA that do not relate to the requirements for SIPs under section 110 of the CAA.
This rule is effective on December 22, 2015, without further notice, unless the EPA receives adverse comment by November 23, 2015. If the EPA receives adverse comment, we will publish a timely withdrawal in the
Submit your comments, identified by Docket ID No. EPA-R10-OAR-2014-0562, by any of the following methods:
•
•
•
•
Keith A. Rose at (206) 553-1949,
Throughout this document whenever “we,” “us,” or “our” are used, it is intended to refer to the EPA.
Title I of the CAA specifies the general requirements for states to submit SIPs to attain and maintain the National Ambient Air Quality Standards (NAAQS) and the EPA's actions regarding approval of those SIPs. The EPA received a submittal from the ODEQ on July 7, 2014 requesting that the EPA approve into the Oregon SIP the revisions to the LRAPA open burning rules (title 47) adopted on March 14, 2008. In general, the revised LRAPA open burning rules make clarifications and provide for additional controls of open burning activities in Lane County. The EPA also received a submittal from the ODEQ on June 30, 2014 that updates Oregon Administrative Rules (OAR) Chapter 340, Division 11, Rules of General Applicability and Organization, relating to contested cases (appeals of ODEQ actions) and OAR Chapter 340, Division 12, Enforcement Procedures and Civil Penalties. These divisions apply across all programs implemented by the ODEQ, including the air quality regulations that the EPA has approved into the SIP.
The July 7, 2014 and June 30, 2014 SIP submittals also contain amendments to OAR 340-200-0040. This rule describes the State's procedures for adopting its SIP and references all of the state air regulations that have been adopted by the ODEQ for approval into the SIP (as a matter of state law), whether or not they have yet been submitted to or approved by the EPA.
LRAPA made numerous revisions throughout title 47, Open Burning. The key substantive changes are discussed below. A more detailed evaluation of the revisions to LRAPA's open burning rules is in the docket for this action. As discussed below, the EPA proposes to find that, overall, the revised rules will provide for additional controls for open burning activities in Lane County, reduce particulate emissions in Lane County, and strengthen Oregon's SIP.
LRAPA made several revisions to the types of open burning exempt from regulation and added one new exemption category. Although residential barbequing remains exempt, LRAPA has clarified that certain prohibited materials, such as garbage or plastic, may not be burned as fuel. The exemption for residential fires for recreational purposes has been narrowed by prohibiting the use of yard waste as fuel and prohibiting such fires altogether on yellow and red home wood heating advisory days called by LRAPA in the winter months within the Eugene/Springfield Urban Growth Boundary (ESUGB) and within the city limits of Oakridge. Religious ceremonial fires have been added as a new category of fires exempt from title 47. See LRAPA 47-005-2.C and 47-010 (definition of “religious ceremonial fires”). LRAPA expects religious ceremonial fires to occur infrequently and the definition requires that such fires be controlled, be “integral to a religious ceremony or ritual,” and that prohibited materials not be burned. Given the narrow scope of this exemption, that the exemptions from title 47 have otherwise been narrowed, and that the other revisions to title 47 generally strengthen the prohibitions on open burning, the EPA finds that the new exemption for religious ceremonial fires will not interfere with attainment or maintenance of the NAAQS or any other applicable requirement of the CAA. The EPA therefore approves the revisions to LRAPA 47-005, Exemptions from these Rules.
The following definitions in LRAPA 47-010 have been revised: Agricultural open burning, commercial wastes, construction wastes, construction open burning, demolition wastes, demolition open burning, Eugene-Springfield Urban Growth Boundary, industrial open burning, and industrial waste. In general, the revisions to these definitions clarify the types of burn and waste categories. For example, through revisions to the definitions of construction waste, demolition waste, and commercial waste, it is now clear that wastes transported offsite are considered commercial waste even if the waste might otherwise meet the definition of construction or demolition waste. Because requirements for the open burning of commercial waste are generally more restrictive, these clarifications make the rules more
Definitions have been added to LRAPA 47-010 for agricultural operation, agricultural waste, bonfire, forest slash open burning, nuisance, recreational fire, religious ceremonial fire, and salvage. The new definition of “religious ceremonial fire” is discussed above in Section II.A.1 and the new definition of “forest slash opening burning” is discussed in Section II.A.3 below. In general, the other new definitions clarify the meaning of terms previously used in the rules and thus enhance the enforceability of the rules.
Because the revised and new definitions in LRAPA 47-010 either increase the stringency of the rules or provide clarification to enhance enforceability, the EPA approves revisions to LRAPA 47-010 except for the definition of “nuisance,” which is discussed in more detail in Section II.A.5 below.
Note that the introductory language in LRAPA 47-010 references title 12 of the LRAPA regulations for additional definitions. Proposed revisions to title 12 were included in a SIP submission that the EPA received on August 28, 2014. The present action does not address those revisions. The EPA will be acting on that submission in a future action.
LRAPA 47-015 contains most of the requirements for open burning, with general requirements to be met for all open burning and specific requirements for residential open burning, construction and demolition open burning, commercial open burning, industrial open burning, and a new category, forest slash open burning.
Requirements for residential open burning have been made more stringent in a number of respects. The ending times for open burns are now set by a LRAPA burning advisory, rather than automatically extending until sunset. All open burning remains prohibited within the city of Eugene, and the prohibition on open burning within the city of Springfield has been expanded so that the burning of woody yard trimmings on lots of a half acre or more is now only allowed between March 1 through June 15 and October 1 through October 31, rather than from October 1 to June 15. The period of allowed residential open burning outside of the Eugene and Springfield city limits but within the ESUGB has similarly been narrowed. The Hazeldell and Siuslaw fire districts have been added to the list of fire districts that must comply with the open burning requirements for fire districts, which include the prohibition on burning construction/demolition debris unless authorized by a letter permit. Therefore, the conditions for open burning in the two newly added fire districts are now more stringent. Finally, a new section restricts residential open burning of woody yard trimmings, leaves and grass in Lane County outside of the affected areas identified in LRAPA 47-015-2.B-F to approved burn days from October 1 through June 15, instead of year around. There have been no substantive changes to the requirements for construction and demolition open burning, commercial open burning, or industrial open burning.
A new section has been added to specifically address forest slash open burning. LRAPA 47-015-6.A confirms that forest slash open burning in areas covered by the Oregon Smoke Management Plan is regulated by the Oregon Department of Forestry under ORS 477.515 and not under LRAPA title 47. Such burning is already specifically exempt from LRAPA title 47 under the current SIP. See LRAPA 47-005-1.D.
LRAPA 47-015-6.B addresses forest slash open burning in Lane County outside of areas covered by the Oregon Smoke Management Plan. Forest slash open burning in such areas is now expressly prohibited within the ESUGB. Forest slash open burning is also prohibited unless authorized by a letter permit under LRAPA 47-020, in the fire districts identified in LRAPA 47-015-2.F and other properties not covered by the Oregon Smoke Management Plan. Maps provided by LRAPA show that there is very limited forest land in Lane County that is not covered by the Smoke Management Plan, and would therefore be covered by the LRAPA forest slash open burning rules.
Any slash burning in Lane County must now be coordinated with the South Cascade and Western Lane districts, and be consistent with slash burning advisories issued by Oregon Department of Forestry. In addition, under LRAPA 47-020-1, letter permits for such forest slash open burning can only be issued on a singly occurring or infrequent basis. According to LRAPA, forest slash open burning was not previously expressly regulated under title 47 prior to 1995. Seen in that light, the regulation of forest slash open burning on land not covered by the Oregon Smoke Management Plan would be an increase in the stringency of the Oregon SIP. The EPA considers the language in LRAPA 47-001 (“all open burning is prohibited in Lane County except as expressly allowed by these rules or if exempted from these rules by Oregon Statute”), which is currently approved in the SIP, however, as potentially prohibiting forest open slash burning on land that is not covered by the Oregon Smoke Management Plan. In that respect, authorizing forest slash open burning through a letter permit under certain conditions could be considered less stringent than the current SIP. In any event, given the many other provisions of this SIP revision that make the SIP more stringent, that only one instance of such open slash burning has been issued a letter permit by LRAPA since 1995, the factors considered by LRAPA and findings LRAPA must make in issuing a letter permit for forest slash open burning in LRAPA 47-020-5 and -6, the EPA concludes that allowing this narrow category of open burning will not interfere with attainment and maintenance of the NAAQS or any other applicable requirement of the CAA. Accordingly, with the exception of LRAPA 47-015-6(B)(5), discussed in Section II.A.5 below, the EPA approves the revisions to LRAPA 47-015, Open Burning Requirements, because the revisions increase the overall stringency of the restrictions on open burning.
LRAPA 47-020 authorizes certain types of open burning under letter permits issued by LRAPA. As discussed in Section II.A.3 above, this section has been amended to add forest slash burning for a single occurrence or on an infrequent basis to the list of the categories of open burning that may be allowed by a letter permit issued by LRAPA. It has also been amended to authorize issuance of letter permits for a bonfire held for a single event. The EPA finds that the potential increase in emissions that would result from these infrequent activities would be de minimis in light of the other restrictions on open burning imposed by the other revisions to title 47 in this SIP submittal.
LRAPA 47-020-5 contains a list of factors to be considered by LRAPA in determining whether to issue a letter permit. This provision has been amended to allow LRAPA to consider as an alternative disposal method whether waste materials can be salvaged.
Because the availability of alternative disposal options mitigates against authorizing open burning under LRAPA's rules, see LRAPA 47-001, expanding the list of what can be
With the exception of certain provisions discussed below in Section II.A.5 that do not relate to the requirements of section 110 of the CAA, the EPA approves the revisions to LRAPA 47-020 because the revisions do not interfere with attainment and maintenance of the NAAQS or any other applicable requirement of the CAA.
LRAPA has removed the table is section 47-030, Summary of Seasons, Areas, and Permit Requirements for Open Burning. This table was a summary of the text explaining what type of burning was allowed in each area of Lane County. Removing this table has no impact on the stringency of the rule.
Title 47 contains several provisions, both previously approved by the EPA into the Oregon SIP, and newly enacted or revised provisions, that relate to nuisance, fire safety, or environmental issues that do not relate to air quality. The EPA's authority to approve SIPs extends to provisions related to attainment and maintenance of the NAAQS and carrying out other specific requirements of section 110 of the CAA. Section 110(k)(6) of the CAA authorizes the EPA, upon a determination that the EPA's action approving, disapproving or promulgating any SIP or plan revision (or any part thereof) was in error, to revise such action as appropriate.
In this action, the EPA is not approving into the SIP and is removing from the SIP the following provisions of title 47 that do not relate to attainment and maintenance of the NAAQS or the other requirements of section 110 the CAA: The definition of “nuisance” in LRAPA 47-010; LRAPA 47-015-1.D (currently in the SIP); LRAPA 47-015-1.H; LRAPA 47-015-6.B(5); LRAPA 47-020-3 (currently in the SIP); LRAPA 47-020-9.I; LRAPA 47-020-10 (first sentence currently in the SIP).
Oregon's June 30, 2014 submittal revises OAR Chapter 340, Division 11, to align with the Oregon Attorney General Model Rules, which address procedures for filing and serving documents in contested cases (appeals of ODEQ actions). These rule revisions were adopted by Oregon on December 11, 2013 and became effective on January 6, 2014. The rules were revised to improve the clarity and completeness of contested case appeals coming before the Environmental Quality Commission.
Division 11 provides authority needed for implementing the SIP and is consistent with the CAA requirements for the issuance of permits and enforcement authority. The EPA is therefore approving the revisions to Division 11 submitted by the ODEQ, subject to the qualifications discussed below in Section III.
Division 12 contains enforcement procedures and civil penalty provisions that apply across all programs implemented by the ODEQ, including the air quality regulations that the EPA has approved into the SIP. Division 12 provides the authority and procedures under which the ODEQ notifies regulated entities of violations, determines the appropriate penalties for violations, and assesses penalties for such violations. The revisions to Division 12 made by the ODEQ implement legislative increases in statutory maximum penalties, align violation classifications and magnitudes with ODEQ program priorities, provide greater mitigating credit for correcting violations, and make minor housekeeping changes.
The EPA has reviewed the revisions to OAR Chapter 340, Division 12 and finds that these rules continue to provide the ODEQ with adequate authority for enforcing the SIP as required by section 110 of the Clean Air Act and 40 CFR 50.230(b). Importantly, OAR 340-012-0160(1) gives the ODEQ the discretion to increase a base penalty to that derived using the next highest penalty matrix value and OAR 340-012-0160(4) gives the ODEQ the discretion to deviate from the penalty matrices and assess penalties of $25,000 per day, per violation based on the facts and circumstances of the individual case. The EPA therefore approves into the SIP the revisions to Division 12 submitted by the ODEQ, subject to the qualifications discussed below in Section III.
The EPA is taking the following action on the revisions to LRAPA title 47, Open Burning, adopted on May 14, 2008, and submitted to the EPA by the ODEQ on July 7, 2014. We approve the revisions to the following sections except as identified below: 47-001, General Policy; 47-005, Exemptions from These Rules; 47-010, Definitions; 47-015, Open Burning Requirements; and 47-020, Letter Permits. As discussed in Section II.A.5 above, because the EPA's authority to approve SIPs extends to provisions related to attainment and maintenance of the NAAQS and carrying out other specific requirements of section 110 of the CAA, we are not approving into the SIP and are removing from the SIP under the authority of CAA section 110(k)(6) the following provisions: The definition of “nuisance” in LRAPA 47-010; LRAPA 47-015-1.D (currently in the SIP); LRAPA 47-015-1.H; LRAPA 47-015-6.B(5); LRAPA 47-020-3 (currently in the SIP); LRAPA 47-020-9.I; LRAPA 47-020-10 (first sentence currently in the SIP).
The EPA also approves revisions to OAR Chapter 340, Division 11, adopted on December 11, 2013 and submitted by the ODEQ on June 30, 2014. The EPA is approving this division, however, only to the extent it relates to implementation of requirements contained in the Oregon SIP. The EPA is not incorporating these rules by reference into the Code of Federal Regulations, however, because the EPA relies on its independent administrative and enforcement procedures under the CAA.
The EPA also approves revisions to OAR Chapter 340, Division 12, adopted on December 11, 2013 and submitted by the ODEQ on June 30, 2014, except for the following provisions that do not relate to air emissions and were not submitted by the ODEQ for approval: OAR 340-012-0027,
The EPA is not approving the revisions to OAR 340-200-0040 in these SIP submittals because these provisions address state SIP adoption procedures and because the Federally-approved SIP consists only of regulations and other requirements that have been submitted by the ODEQ and approved by the EPA.
In this rule, the EPA is finalizing regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is incorporating by reference the ODEQ regulations described in the amendments to 40 CFR part 52 set forth below. The EPA has made, and will continue to make, these documents generally available electronically through
Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, the EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this action merely approves state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the Clean Air Act; and
• does not provide the 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 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).
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by December 22, 2015. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. Parties with objections to this direct final rule are encouraged to file a comment in response to the parallel notice of proposed rulemaking for this action published in the proposed rules section of today's
Environmental protection, Air pollution control, Intergovernmental relations, Incorporation by reference, Particulate matter, Reporting, and recordkeeping requirements.
For the reasons stated in the preamble, 40 CFR part 52 is amended as follows:
42 U.S.C. 7401
The revisions and additions read as follows:
(c) * * *
(e) EPA Approved Nonregulatory provisions and Quasi-Regulatory Measures.
Indian Health Service, Health and Human Services.
Final rule.
The Department of Health and Human Services (HHS or the Department) is revising its regulations governing administrative appeals to reflect a change of address for the Interior Board of Indian Appeals (IBIA). The IBIA moved to a new address at 801 North Quincy St., Suite 300, Arlington, VA 22203 effective February 11, 2002.
This rule is effective October 23, 2015.
Carl Mitchell, Acting Director, Division of Regulatory Affairs, Indian Health Service, 801 Thompson Avenue, Rockville, Maryland 20852, Telephone: (301) 443-1116.
Through a two-person panel of administrative judges, the Interior Board of Indian Appeals (IBIA) has the authority to consider appeals from decisions of agency officials and administrative law judges in cases under the Indian Self-Determination and Education Assistance Act (ISDEAA). Located within the Department of Interior's Office of Hearings and Appeals (OHA), IBIA is separate and independent from the Bureau of Indian Affairs (BIA) and the Assistant Secretary—Indian Affairs.
Effective February 11, 2002, the IBIA was relocated to 801 North Quincy Street, Arlington, Virginia. To avoid confusion with appeals, HHS is updating its administrative appeals regulations to reflect the IBIA's new street address.
The Department has determined that the public notice and comment provisions of the Administrative Procedure Act, 5 U.S.C. 553(b), do not apply to this rulemaking because the changes being made relate solely to matters of agency organization, procedure, and practice. It, therefore, satisfies the exemption from notice and comment rulemaking in 5 U.S.C. 553(b)(A).
Moreover, the Department has determined that there is good cause to waive the requirement of publication 30 days in advance of the rule's effective date under 5 U.S.C. 553(d). The error in the IBIA's location could cause misdirection of appeals. Thus, if the changes in this rule were to become effective 30 days after publication, it could cause further delays in processing appeals. Because an earlier effective date benefits the public, there is good cause for making this rule effective in less than 30 days, as permitted by 5 U.S.C. 553(d)(3).
The Department has reviewed this rule under the following statutes and executive orders governing rulemaking procedures: The Unfunded Mandates Reform Act of 1995, 2 U.S.C. 1501
For the reasons set forth in the preamble, the Department, through the Indian Health Service amends subpart P of title 42 of the Code of Federal Regulations part 137 to read as follows:
25 U.S.C. 458
In rule document 2015-26449 beginning on page 63130 in the issue of Monday, October 19, 2015, make the following correction:
On page 63131, in the table, in the first column, in the Region VII entry “Kansas: 23 Hanover, City of, Washington County” should read “Kansas: Hanover, City of, Washington County”.
Federal Communications Commission.
Final rule.
In this document, the Federal Communications Commission (“Commission”) amends the portion of its rules known as the “Contest Rule” to permit broadcast licensees to comply with their obligation to disclose material contest terms either by broadcasting those terms or by making them available in writing on a publicly accessible Internet Web site. In particular, the Commission amends the Contest Rule to allow licensees to satisfy their disclosure obligation by posting material contest terms on the station's Web site, the licensee's Web site, or, if neither the individual station nor the licensee has its own Web site, any Internet Web site that is readily accessible to the public. The Commission also adopts requirements that define the disclosure obligation in cases where a licensee has chosen to meet its obligation through an Internet Web site.
This rule contains information collection requirements that have not been approved by OMB. The Commission will publish a document in the
Raelynn Remy,
This is a summary of the Commission's
This document contains new or modified information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA).
1. Our “Contest Rule,” Section 73.1216 of our rules, requires broadcast licensees to disclose on air the material terms of contests that they broadcast. In this
2. We also adopt, with some modifications, requirements proposed in the Notice of Proposed Rulemaking that define the disclosure obligation in cases where a licensee has chosen to meet its obligation through an Internet Web site. Specifically, we revise the Contest Rule to specify that in such cases a licensee: (i) Must broadcast the relevant Web site address periodically with information sufficient for a consumer easily to find material contest terms online; (ii) must establish a link or tab to material contest terms on the Web site's home page; (iii) must maintain contest terms online for a period of at least thirty days after the contest has ended; and (iv) must announce on air that the material terms of a contest have changed since the contest was first announced, where that is the case, and direct participants to the Web site to review the changes. As discussed below, the announcements of any change in contest terms must be made within 24 hours of the change and periodically thereafter. Finally, we require that licensees ensure that any material terms disclosed on a Web site conform in all substantive respects to those mentioned over the air.
3. The actions we take in this
4. Radio and television broadcast stations often conduct contests as a means of entertainment, promoting station support, and deepening audience engagement.
5. In January 2012, Entercom Communications Corp. (“Entercom” or “Petitioner”) filed an unopposed Petition for Rulemaking asking the Commission to update the disclosure requirements of Section 73.1216.
6. As advocated by all of the commenters, we amend the Contest Rule to allow broadcast licensees to meet their obligation to disclose material contest terms either by broadcasting the material terms or by making those terms available in written form on a readily accessible public Internet Web site. We agree with parties who assert that, given the ubiquitous nature of the Internet and current consumer expectations about how to obtain information, broadcast disclosure of material contest terms no longer reflects the best means of conveying such information to the public in all cases. For example, although on-air disclosure may be preferable in certain circumstances,
7. Based on the record, we conclude that allowing broadcasters to meet their obligation to disclose material contest terms through the Internet in lieu of broadcasting the terms will benefit consumers by improving their access to important contest information, to the extent that our action results in greater use of online disclosure. Because the current rule requires that licensees disclose material contest terms via broadcast announcements periodically, audience members interested in a contest may not hear or see contest disclosures if they are not tuned into the broadcast at the time the announcement is aired. Moreover, even in cases where prospective contestants hear or see a contest disclosure, the length or complexity of contest terms or the speed at which licensees communicate those terms may render it difficult for many to comprehend or recall the information conveyed. For these reasons, we agree with parties who assert that broadcasters' online posting of material terms will allow consumers to obtain “on demand” access to those terms and to review them at their convenience, thereby increasing the likelihood that contest terms will be understood and remembered.
8. We find that this revision to the Contest Rule is consistent with consumer expectations about how to obtain contest information. As many parties note, the public today accesses information in ways that are dramatically different from how they did when the Contest Rule was adopted. The Internet has become a fundamental part of consumers' daily lives and now represents the medium used most by the public to obtain information instantaneously. Given that Americans today are accustomed to using the Internet to obtain a broad range of information, we agree with parties who assert that consumers reasonably expect to obtain information about licensee-conducted contests through the Internet. Indeed, as some parties note, broadcasters already use the Internet to post contest-related information, and consumers often enter and participate in contests via the Internet. Amending the Contest Rule to permit reliance on online disclosure of material contest terms thus brings the rule into alignment with current consumer expectations.
9. As noted, permitting reliance on online disclosure of contest terms also will benefit broadcasters by affording them greater flexibility in the manner of their compliance with Section 73.1216 and by freeing up air time for other programming. Because many broadcasters already have dedicated Web sites where they can post complete contest information that the public can access “on demand,” and because we are not requiring broadcasters to use online posting if they prefer to broadcast contest terms over the air, we agree with parties who assert that the benefits of this rule change outweigh any associated costs.
10. Although this rule revision is intended, in part, to give broadcasters more flexibility in how they satisfy their obligation to disclose material contest terms, we find that the public interest will be served by establishing specific requirements that define the disclosure obligation in cases where a broadcaster chooses to meet that obligation through an Internet Web site. In particular, we believe that these requirements, which are comparable to those that apply to on-air disclosures,
11.
12.
13. Consistent with broadcasters' existing obligation to broadcast contest rule disclosures “periodically,” we conclude further that licensees must broadcast the Web site address where contest terms are posted “periodically” during the period of the contest. Although we proposed in the
14. We decline at this time to adopt a more prescriptive requirement governing the frequency of broadcast identification of the Web site address where contest terms are posted as some parties have suggested.
15.
16.
17.
18.
19. As required by the Regulatory Flexibility Act of 1980, as amended (“RFA”)
20. This proceeding stems from an unopposed Petition for Rulemaking filed by Entercom Communications Corp. requesting that the Commission update Section 73.1216 of its rules governing broadcast licensee-conducted contests (the “Contest Rule”)
21. In the accompanying
22. The
23. No comments were filed that specifically addressed the IRFA.
24. The RFA directs agencies to provide a description of and, where feasible, an estimate of the number of small entities that may be affected by the proposed rules, if adopted.
25.
26. Apart from the U.S. Census, the Commission has estimated the number of licensed commercial television stations to be 1,387 stations.
27.
28. We note, however, that in assessing whether a business concern qualifies as “small” under the above definition, business (control) affiliations
29.
30. Apart from the U.S. Census, the Commission has estimated the number of licensed commercial AM radio stations to be 4,553 stations and the number of commercial FM radio stations to be 6,622, for a total number of 11,175.
31.
32. We note again, however, that in assessing whether a business concern qualifies as “small” under the above definition, business (control) affiliations
33. In this section, we identify the reporting, recordkeeping, and other compliance requirements for small entities that the Commission adopts in the
34.
35.
• to broadcast the relevant Web site address periodically with information sufficient for a consumer to easily find material contest terms online;
• to establish a link or tab to material contest terms on the Web site's home page;
• to maintain contest terms online for a period of at least thirty days after the contest has ended;
• in cases where such entities change the material terms of a contest after the contest is first announced, to announce on air that the contest rules have changed and direct participants to the Web site to review the changes, and to make such announcements on air within 24 hours of the change on the Web site and periodically thereafter; and
• to ensure that any material terms disclosed on a Web site conform in all substantive respects to those mentioned over the air.
36.
37. Based on the record, we cannot estimate with precision the impact of the rules adopted in the
38. The RFA requires an agency to describe any significant, specifically small business, alternatives that it has considered in reaching its proposed approach, which may include the following four alternatives (among others): (1) The establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities; (2) the clarification, consolidation, or simplification of compliance and reporting requirements under the rule for such small entities; (3) the use of performance, rather than design, standards; and (4) an exemption from coverage of the rule, or any part thereof, for small entities.
39. The accompanying
40. The Commission will send a copy of this
41. This document contains new or modified information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA). The requirements will be submitted to the Office of Management and Budget (OMB) for review under Section 3507(d) of the PRA. OMB, the general public, and other Federal agencies will be invited to comment on the new or modified information collection requirements contained in this proceeding. In addition, we note that pursuant to the Small Business Paperwork Relief Act of 2002, we previously sought specific comment on how the Commission might further reduce the information collection burden for small business concerns with fewer than 25 employees.
42. Accordingly, IT IS ORDERED that, pursuant to the authority contained in Sections 4(i), 4(j) and 303 of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 154(j), and 303, this
43. IT IS FURTHER ORDERED that, pursuant to the authority found in Sections 4(i), 4(j) and 303 of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 154(j), and 303, the Commission's rules ARE HEREBY AMENDED as set forth in Appendix B.
44. IT IS FURTHER ORDERED that the Commission's Consumer and
45. IT IS FURTHER ORDERED that the Commission SHALL SEND a copy of this
Advertising, Consumer protection, Fraud, Television broadcasters.
For the reasons discussed in the preamble, the Federal Communications Commission amends 47 CFR part 73 as follows:
47 U.S.C. 154, 303, 334, 336, and 339.
(a) A licensee that broadcasts or advertises information about a contest it conducts shall fully and accurately disclose the material terms of the contest, and shall conduct the contest substantially as announced or advertised over the air or on the Internet. No contest description shall be false, misleading or deceptive with respect to any material term.
(b) The disclosure of material terms shall be made by the station conducting the contest by either:
(1) Periodic disclosures broadcast on the station; or
(2) Written disclosures on the station's Internet Web site, the licensee's Web site, or if neither the individual station nor the licensee has its own Web site, any Internet Web site that is publicly accessible.
(c) In the case of disclosure under paragraph (b)(1) of this section, a reasonable number of periodic broadcast disclosures is sufficient. In the case of disclosure under paragraph (b)(2) of this section, the station shall:
(1) Establish a conspicuous link or tab to material contest terms on the home page of the Internet Web site;
(2) Announce over the air periodically the availability of material contest terms on the Web site and identify the Web site address where the terms are posted with information sufficient for a consumer to find such terms easily; and
(3) Maintain material contest terms on the Web site for at least thirty days after the contest has concluded. Any changes to the material terms during the course of the contest must be fully disclosed on air within 24 hours of the change on the Web site and periodically thereafter or the fact that such changes have been made must be announced on air within 24 hours of the change, and periodically thereafter, and such announcements must direct participants to the written disclosures on the Web site. Material contest terms that are disclosed on an Internet Web site must be consistent in all substantive respects with those mentioned over the air.
Note 1 to § 73.1216: For the purposes of this section:
(a) A contest is a scheme in which a prize is offered or awarded, based upon chance, diligence, knowledge or skill, to members of the public.
(b) Material terms include those factors which define the operation of the contest and which affect participation therein. Although the material terms may vary widely depending upon the exact nature of the contest, they will generally include: How to enter or participate; eligibility restrictions; entry deadline dates; whether prizes can be won; when prizes can be won; the extent, nature and value of prizes; basis for valuation of prizes; time and means of selection of winners; and/or tie-breaking procedures.
Note 2 to § 73.1216: In general, the time and manner of disclosure of the material terms of a contest are within the licensee's discretion. However, the obligation to disclose the material terms arises at the time the audience is first told how to enter or participate and continues thereafter.
Note 3 to § 73.1216: This section is not applicable to licensee-conducted contests not broadcast or advertised to the general public or to a substantial segment thereof, to contests in which the general public is not requested or permitted to participate, to the commercial advertisement of non-licensee-conducted contests, or to a contest conducted by a non-broadcast division of the licensee or by a non-broadcast company related to the licensee.
Department of Energy.
Final rule.
The Department of Energy (DOE) is adopting as final, with changes, a rule amending the Department of Energy Acquisition Regulation (DEAR) to add clauses regarding applicable export control requirements for DOE contracts. The rule recognizes contractor responsibilities to comply with all applicable export control laws and regulations in the performance of DOE contracts and prescribes Export Clauses to address these responsibilities.
Lawrence Butler, (202) 287-1945 or
The purpose of this rulemaking is to add new DEAR Subparts 925.71 and 970.2571 to clarify requirements concerning compliance with export control laws and regulations applicable in the performance of DOE contracts.
Export control laws and regulations that may apply to a DOE contract include, but are not limited to: The Atomic Energy Act of 1954 (42 U.S.C. 2011
DOE provided summaries of these export control laws in section II of its proposed rule. See 78 FR 35195 (June 12, 2013).
DOE is amending the DEAR to add provisions similar to the 2013 amendments to the Defense Federal Acquisition Regulation Supplement (DFARS) (DFARS 225, Foreign Acquisition, and DFARS 252, 78 FR 36108, June 17, 2013); DFARS 252, Foreign Acquisition, 78 FR 48331, August 8, 2013; and to the DFARS Procedures, Guidance, and Information (PGI) 225 “Foreign Acquisition” (revised June 26, 2013).
Part 925 is amended by adding new section 925.71 to set forth requirements for contractors concerning compliance with U.S. export control laws and regulations.
Points of contact and specific U.S. government agency requirements for export controls can be found as follows:
Department of Commerce (DOC):
Department of Energy, National Nuclear Security Administration, Office of Nonproliferation and International Security:
Nuclear Regulatory Commission:
Department of State:
Department of Treasury:
DOE contractors are responsible for complying with export control requirements applicable to their contracts as set forth in new DEAR Export Clauses. It is a contractor's responsibility to comply with all applicable export control laws and regulations. This responsibility exists independent of, and is not established or limited by, this DEAR rulemaking.
Part 952 is amended by adding new clause 952.225-71 to set forth requirements for DOE contractors concerning compliance with applicable export control laws and regulations.
Points of contact and specific U.S. government agency requirements for export controls can be found as follows:
Department of Commerce (DOC):
Department of Energy, National Nuclear Security Administration, Office of Nonproliferation and International Security:
Nuclear Regulatory Commission:
Department of State:
Department of Treasury:
DOE contractors are responsible for complying with export control requirements applicable to their contracts as set forth in new DEAR Export Clauses. It is a contractor's responsibility to comply with all applicable export control laws and regulations. This responsibility exists independent of, and is not established or limited by, this DEAR rulemaking.
Subpart 970.25 is amended by adding new section 970.2571 to set forth requirements for management and operating contractors concerning compliance with applicable export control laws and regulations. Subpart 970.52 is amended by adding new clause 970.5225-1 to set forth requirements for management and operating contractors concerning compliance with applicable export control laws and regulations.
Points of contact and specific U.S. government agency requirements for U.S. export controls can be found as follows:
Department of Commerce (DOC):
Department of Energy, National Nuclear Security Administration, Office of Nonproliferation and International Security:
Nuclear Regulatory Commission:
Department of State:
Department of Treasury:
DOE management and operating contractors are responsible for complying with export control requirements applicable to their contracts as set forth in new DEAR Export Clauses. It is the contractor's responsibility to comply with all applicable export control laws and regulations. This responsibility exists independent of, and is not established or limited by, this DEAR rulemaking.
DOE published a notice of proposed rulemaking (NOPR) on June 12, 2013 (78 FR 35195). The NOPR reflected the approach previously taken by the Department of Defense (DoD) in the Defense Acquisition Regulations Supplement (DFARS) to address requirements for complying with export control laws and regulations when performing DoD contracts. DOE has received recommendations from the General Accounting Office and the DOE Inspector General to modify the DEAR for the same purpose. DOE received comments from 15 organizations in response to the NOPR. In addition, within days of publication of the NOPR, the DoD revised the DFARS to address issues similar to those reflected in comments received on the NOPR and provided guidance relating to the
The following paragraphs describe the changes included in this final rule as a result of those comments and provide DOE's response to the comments received.
(a) All notification and reporting requirements have been removed.
(b) The requirement for contractors to comply with DOE directives “in effect on the date of the contract award” has been removed.
(c) References to “transfers” have been removed.
(d) References to specific DOE Orders have been removed.
(e) The Export Restriction Notice has been removed from the Export Clauses.
(f) The phrase “subject to export controls” has been removed from the Export Clauses.
(g) All listings of U.S. export control laws and regulations are preceded by, “include, but are not limited to:”
(h) All references to “export-controlled items” and “export control of items” have been removed. The rule addresses “compliance with export control laws and regulations” and does not attempt to define what is and is not export controlled.
1. Comment: Six respondents claimed that export control laws exist and already apply to U.S. persons, regardless of whether a contractor represents to DOE that it is complying with applicable export laws.
Response: As stated in the NOPR, export compliance responsibilities exist independent of and are not established or limited by the proposed rule. It is customary practice for laws and regulations applicable to DOE contracts to be listed in the contracts. In addition, DOE is requiring the new Export Clauses to be added to all applicable contracts. Listing applicable export laws and regulations in the Export Clauses will help ensure that contractors are aware of their responsibilities, emphasize the importance to DOE of contractor compliance with such laws and regulations, and minimize the risk of non-compliance with U.S. laws and regulations that could have major programmatic and financial impacts on DOE and contractors. No change was made to the text as a result of this comment.
2. Comment: Six respondents claimed that the rule encroaches on the export authority of other U.S. export licensing authorities.
Response: The rule does not affect the export authority of any U.S. Government agency. The purpose of the rule is to direct DOE contractors to seek guidance from and to communicate with export licensing officers at export licensing agencies and not to ask DOE Contracting Officers for assistance in complying with export control requirements. The rule provides explicit instructions to DOE Contracting Officers, if asked by a DOE contractor to provide export assistance, to direct contractors to applicable export laws and regulations and to the agencies administering them. The final rule makes it clear that DOE does not have an export compliance officer overseeing DOE contractor export activities, and that contractors are responsible for compliance with export controls. No change was made to the text as a result of this comment.
3. Comment: Four respondents claimed the proposed rule has existing or potential inconsistencies with export control authorities.
Response: As noted above, the purpose of the rule is to direct DOE contractors to seek guidance from and to communicate with export licensing officers at export licensing agencies and not to ask for export control compliance assistance from DOE Contracting Officers. The final rule has been revised to remove reporting and marking requirements, as well as language cited by one respondent as potentially inconsistent with other authorities.
4. Comment: One respondent expressed concern as to how differences of opinion on the applicability of export control requirements between agencies responsible for administering the laws and the DOE Contracting Officer would be resolved.
Response: The rule makes clear that DOE Contracting Officers do not make any decisions regarding the applicability of export control laws or regulations. The appropriate licensing agency determines whether export control requirements apply. It is a contractor's responsibility to adhere to all relevant export control laws and regulations. No change was made to the text as a result of this comment.
5. Comment: One respondent claimed that DOE is potentially setting up a conflict for a contractor between complying with changes in export laws and regulations that are not yet changed in its contract clause.
Response: The listing of export control laws and regulations in the Export Clauses in the final rule are preceded by “include, but are not limited to:”. Any changes in U.S. export laws or regulations would apply to a contractor because the Export Clauses require compliance with all applicable export control laws and regulations. No change was made to the text as a result of this comment.
6. Comment: Two respondents alleged that the proposed rule is inconsistent with the Export Control Reform Initiative.
Response: The final rule is consistent with the Export Control Reform Initiative (ECRI). The purpose of this rule is to simplify the export process for DOE contractors, by directing them to the proper export licensing authorities. Reporting requirements have been removed from the final rule.
7. Comment: Three respondents claimed that the proposed rule is redundant to DEAR 970.5204-2 Laws, Regulations and DOE Directives, because that clause adequately covers compliance with export laws and regulations.
Response: The rule clarifies DOE contractor and Contracting Officer responsibilities regarding export controls not clearly stated in any other law or regulation. The Export Clauses clarify that DOE contractors are to contact appropriate export licensing agencies and not DOE Contracting Officers with questions regarding export control compliance. The Export Clauses direct DOE Contracting Officers to address contractor export control questions by directing them to relevant export control laws and regulations and licensing agencies. No change was made to the text as a result of this comment.
8. Comment: One respondent questioned the requirement for contractors to comply with DOE directives “in effect on the date of the contract award,” as individual DOE contracts specify applicable DOE directives for each DOE contract.
Response: DOE acknowledges that contracts specify applicable DOE directives. This language has been removed from the final rule.
9. Comment: Two respondents claimed that DOE already has adequate contractual enforcement tools.
Response: The purpose of the rule is not to provide additional enforcement tools. This rule is needed to clarify DOE contractor and Contracting Officer export control responsibilities not
10. Comment: Six respondents claimed that export control requirements are not needed in the DEAR and that the Federal Acquisition Regulation (FAR) limits agency acquisition regulations to those necessary to implement FAR policies and procedures.
Response: The final rule provides necessary policies and procedures not included in the FAR. It clarifies that DOE contractors are to consult appropriate export licensing agencies and not DOE Contracting Officers with questions regarding export compliance. The final rule directs DOE Contracting Officers to handle export control questions posed by contractors by directing the contractors to the relevant export licensing agencies. This rule is needed to clarify DOE contractor and DOE Contracting Officer responsibilities that are not clearly stated in any other law or regulation. No change was made to the text as a result of this comment.
11. Comment: Six respondents claimed that the proposed rule exceeds the stated purpose of the rule, which is to amend the DEAR for consistency with a 2010 amendment to the DFARS. They said that the proposed rule is not consistent with the revised DFARS clauses.
Response: The final rule reflects the approach taken in the June 17, 2013, changes to 225.79 and 252.225-7048 of the DFARS (Foreign Acquisition, 78 FR 36108) and to the June 17, 2013 changes to Part 225.79 of the DFARS PGI-225 (Foreign Acquisition). No change was made to the text as a result of this comment.
12. Comment: Three respondents claimed that the proposed rule is ineffective as a way to respond to 2004 and 2007 DOE Inspector General (IG) and 2011 Government Accountability Office (GAO) reports on DOE contractor non-compliance with export laws.
Response: The rule responds to DOE IG and GAO recommendations in the cited reports for DOE to provide specific export control guidance to DOE contractors. In particular, the 2007 DOE IG report recommended that DOE “ensure that export control guidance is disseminated and implemented throughout the complex.” To implement that recommendation, the IG report stated that “NNSA management should expedite action, such as issuing a directive or modifying the Department of Energy Acquisition Regulation (DEAR), to fully implement the open recommendation.” The 2011 GAO report repeated its prior recommendations for DOE to provide guidance to its contractors. The proposed rule is in direct response to the DOE IG recommendation to modify the DEAR, as well as the recommendations in the GAO report. No change was made to the text as a result of this comment.
13. Comment: Two respondents claimed that the proposed rule unfairly asks Contracting Officers to make export control decisions for which they are not trained. One respondent proposed rewording the requirement for Contracting Officers to insert the export control clause as follows: “The Contracting Officer shall insert the clause at 952.225-71, Compliance with export control laws, regulations and directives (Export Clause), in all solicitations and contracts.”
Response: The purpose of the new rule is to set forth the responsibilities of DOE contractors and DOE Contracting Officers concerning contractor compliance with export-controlled activities. Contracting Officers are required to include the Export Clause at DEAR 952.225-71 or DEAR 970.5225-1 in solicitations and contracts that would involve export-controlled activities. While the rule has been revised to be applicable to “all solicitations and contracts,” export control laws would not be applicable to solicitations and contracts that do not involve export-controlled activities. As noted above, the revised language is similar to the policy approach taken DoD.
14. Comment: Nine respondents claimed that certain reporting requirements included in the Export Clauses would unduly burden DOE contractors because the requirement of a timely, written notification of export controls and compliance for DOE contracts would be an overbroad approach to ensuring export control compliance. Also, the requirement to flow down the reporting requirement would impose administrative and audit burdens on contractors.
Response: The final rule removes the requirements for a contractor to notify the DOE Contracting Officer when the contract may require export activities and for a contractor to assure the DOE Contracting Officer of its ability to comply with U.S. export laws and regulations. The reporting and notification requirements in the proposed rule were not required by any law or regulation, or recommended by any auditors. The purpose of the Export Clauses is to clarify that DOE contractors should consult appropriate export licensing agencies, and not DOE Contracting Officers, with questions regarding compliance with export-controlled activities. The reporting and notification requirements were removed from the rule to avoid any implication that DOE Contracting Officers have any export compliance responsibilities.
15. Comment: Two respondents were concerned about the impact on small business subcontractors and universities.
Response: U.S. export control laws and regulations already apply to activities conducted by small businesses and by universities that have DOE contracts, so there would be no substantive change regarding export control requirements applicable to these entities. No change was made to the text as a result of this comment.
16. Comment: Three respondents claimed that the proposed rule is not consistent with National Security Decision Directive (NSDD) 189 because “products” most often generated and disseminated while performing fundamental research are scientific findings excluded from export regulations under the “Fundamental Research Exclusion” set forth in NSDD-189 and the exclusion of fundamental research from export controls in EAR and ITAR provisions.
Response: NSDD 189 establishes a national policy that, to the maximum extent possible, the products of fundamental research shall remain unrestricted. NSDD 189 provides that no restrictions may be placed upon the conduct or reporting of federally funded fundamental research that has not received national security classification, except as provided in applicable U.S. statutes. As a result, contracts confined to the performance of unclassified fundamental research generally do not involve any export-controlled activities. NSDD 189 does not take precedence over statutes. As it clearly states in the directive, NSDD 189 does not exempt any research from statutes that apply to export control laws and regulations. In addition, NSDD 189 is focused on the products of fundamental research and does not exempt access to export-controlled technology used or generated during the conduct of fundamental research. The final rule therefore is consistent with NSDD-189 regarding fundamental research because it does not have an impact on the NSDD-189 exemption for fundamental research and it does not modify restrictions already imposed by U.S. export control laws and regulations on research.
DFARS PGI-225.79 (revised June 17, 2013) and [the final rule on the release of fundamental research information in DFARS 252.204-7000 (August 8, 2013) address release of fundamental research information]. Note that the revised
17. Comment: Two respondents questioned the scope of the Export Restriction Notice requirement.
Response: The Export Restriction Notice requirement has been removed from the final rule because requirements for the use of such a notice are defined in 41 CFR 109 and do not need to be restated in this rule.
18. Comment: Three respondents recommended that DOE would be better served by providing educational materials to contractors to increase export compliance awareness.
Response: The purpose of the new rule is to direct DOE contractors to seek guidance from and to communicate with export licensing officers at appropriate export licensing agencies, and not to ask for export control compliance assistance from DOE Contracting Officers. Compliance training offices of Department of Commerce, Department of State and other agencies provide appropriate training on their respective export regulations. No change was made to the text as a result of this comment.
19. Comment: Two respondents believed that DOE may inadvertently assume liability because of requirements in the Export Clauses should a contractor be in non-compliance with export control requirements.
Response: DOE will not assume any liability due to inclusion of the Export Clauses in contracts or for contractor noncompliance with export control requirements. No change was made to the text as a result of this comment.
20. Comment: Eight respondents claimed that the proposed rule potentially increases DOE contractors' risk by specifically listing regulations in the contract. They also were concerned that contractors could be liable under the False Claims Act and other laws for their actions or for those of their subcontractors. If the contractor is not in compliance with export control regulations, it may also be subject to Qui Tam penalties, and the rule would make failure to comply with export regulations a contractual obligation. This liability may be assumed by the M&O contractor for all of its subcontractors, including lower-tier subcontractors.
Response: The Export Clauses in the final rule do not require reporting or written assurances. Contractors will not assume new liabilities due to insertion of the Export Clauses in DOE contracts.
21. Comment: One respondent claimed that the proposed rule potentially increases DOE contractors' risk by requiring the contractor to identify specific aspects of the contract governed by export laws.
Response: For the reasons stated previously, reporting and written assurance requirements have been removed from the final rule.
22. Comment: One respondent claimed that adoption of the proposed regulation would increase costs for DOE procurements.
Response: For the reasons stated previously, reporting requirements and written assurances have been removed from the final rule. The only
23. Comment: One respondent believed that the rule affects 10 CFR part 810 procedures for contractors subject to that regulation.
Response: The proposed rule does not affect implementation of 10 CFR part 810 with respect to DOE program activities. No change was made to the text as a result of this comment.
24. Comment: One respondent claimed that DOE Contracting Officers will be required to submit all DOE contracts to the Office of Nonproliferation and International Security (NIS) of the National Nuclear Security Administration for 10 CFR part 810 review.
Response: The reporting requirements have been removed from the revised rule. The rule does not place any requirements on DOE Contracting Officers to submit contracts to the office now called the Office of Nonproliferation and Arms Control for 10 CFR part 810 review. No change was made to the text as a result of this comment.
25. Comment: Two respondents asked that this rule to be pursued in conjunction with the revised 10 CFR part 810.
Response: The final rule amending 10 CFR part 810 (part 810) was issued on February 23, 2015. 80 FR 9359 (Feb. 23, 2014). The purpose of that final rule and this final rule are different. Part 810 controls the export of unclassified nuclear technology and assistance, and is one of the export rules that may apply to contractors. It was revised to, among other things, reflect current global civil nuclear trade practices. The purpose of this rule final is to direct DOE contractors to seek guidance from and to communicate with export licensing officers at export licensing agencies regarding export rules such as 10 CFR part 810. No change was made to the text as a result of this comment.
26. Comment: Two respondents stated that the meaning of “transfer” is not clear.
Response: References to “transfers” have been removed from the final rule.
27. Comment: One respondent stated that the list of items to be transferred that are subject to the Notice is ambiguous.
Response: The Export Restriction Notice has been removed from the rule.
28. Comment: One respondent pointed out that DOE cites obsolete and unavailable references with regard to DoD directives. For instance, DOE lists DOE Order 580.1A which directs the reader to follow requirements in a DoD Demilitarization Manual 4160.21-M-1, that was cancelled and replaced. In addition, the replacement (DoD 4160.28-M series) directs users to obtain disposal guidance for ITAR items from Web sites that are available only to DoD components or those with .mil email addresses.
Response: References to specific DOE Orders in the rule have been removed. References in the NOPR were current at the time that it was published.
29. Comment: Six respondents recommended that the rule more closely follow the DoD example in the revised DFARS.
Response: The final rule has been revised consistent with June 17, 2013, changes to sections 225.79 and 252.225-7048 of the DFARS and the DFARS PGI-225.
30. Comment: One respondent disagreed with the implication in the Export Restriction Notice that all items are subject to export controls.
Response: The Export Restriction Notice has been removed from the final rule. As noted above, the phrase “subject to export controls” has been removed from the Export Clauses.
Today's regulatory action has been determined not to be a “significant regulatory action” under Executive Order 12866, “Regulatory Planning and Review,” (58 FR 51735, October 4, 1993). Accordingly, this rule is not subject to review under the Executive Order by the Office of Information and Regulatory Affairs (OIRA) of the Office of Management and Budget (OMB).
DOE has also reviewed this regulation pursuant to Executive Order 13563,
DOE emphasizes as well that Executive Order 13563 requires agencies to use the best available techniques to quantify anticipated present and future benefits and costs as accurately as possible. In its guidance, the Office of Information and Regulatory Affairs has emphasized that such techniques may include identifying changing future compliance costs that might result from technological innovation or anticipated behavioral changes. DOE believes that today's final rule is consistent with these principles, including the requirement that, to the extent permitted by law, agencies adopt a regulation only upon a reasoned determination that its benefits justify its costs and, in choosing among alternative regulatory approaches, those approaches maximize net benefits.
With respect to the review of existing regulations and the promulgation of new regulations, section 3(a) of Executive Order 12988, “Civil Justice Reform,” 61 FR 4729 (February 7, 1996), imposes on Executive agencies the general duty to adhere to the following requirements: (1) Eliminate drafting errors and ambiguity; (2) write regulations to minimize litigation; and (3) provide a clear legal standard for affected conduct rather than a general standard and promote simplification and burden reduction.
With regard to the review required by section 3(a), section 3(b) of Executive Order 12988 specifically requires that Executive agencies make every reasonable effort to ensure that the regulation: (1) Clearly specifies the preemptive effect, if any; (2) clearly specifies any effect on existing Federal law or regulation; (3) provides a clear legal standard for affected conduct while promoting simplification and burden reduction; (4) specifies the retroactive effect, if any; (5) adequately defines key terms; and (6) addresses other important issues affecting clarity and general draftsmanship under any guidelines issued by the Attorney General. Section 3(c) of Executive Order 12988 requires Executive agencies to review regulations in light of applicable standards in section 3(a) and section 3(b) to determine whether they are met or it is unreasonable to meet one or more of them. DOE has completed the required review and determined that, to the extent permitted by law; these proposed regulations meet the relevant standards of Executive Order 12988.
The Regulatory Flexibility Act (5 U.S.C. 601
As required by Executive Order 13272, “Proper Consideration of Small Entities in Agency Rulemaking,” 67 FR 53461 (August 16, 2002), DOE published procedures and policies on February 19, 2003, to ensure that the potential impacts of its rules on small entities are properly considered during the rulemaking process. 68 FR 7990 (February 19, 2003), DOE has made its procedures and policies available on the Office of the General Counsel's Web site (
DOE certifies that this rule would not have a significant impact on a substantial number of small entities because the rule is intended only to recognize existing export control compliance obligations and to clarify the role of DOE and its contracting officers in relation to these requirements. The rule itself does not impose any new requirements on manufacturers. In addition, DOE notes that the reporting requirements referenced in the proposed rule have been eliminated from the final rule for the reasons discussed in response to the comments received on this issue. DOE transmitted this certification to the Small Business Administration (SBA) as required by 5 U.S.C. 605(b).
This final rule does not impose a collection of information requirement subject to the Paperwork Reduction Act, 44 U.S.C. 3501
DOE has concluded that promulgation of this final rule falls into a class of actions which would not individually or cumulatively have significant impact on the human environment, as determined by DOE's regulations (10 CFR part 1021, subpart D) implementing the National Environmental Policy Act (NEPA) of 1969 (42 U.S.C. 4321
Executive Order 13132, 64 FR 43255 (August 4, 1999), imposes certain requirements on agencies formulating and implementing policies or regulations that preempt State law or that have federalism implications. Agencies are required to examine the constitutional and statutory authority supporting any action that would limit the policymaking discretion of the States and carefully assess the necessity for such actions. DOE has examined today's rule and has determined that it does not preempt State law and does 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. No further action is required by Executive Order 13132.
The Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4) generally
Section 654 of the Treasury and General Government Appropriations Act, 1999 (Pub. L. 105-277), requires Federal agencies to issue a Family Policymaking Assessment for any rule or policy that may affect family well being. This rule will have no impact on family well-being. Accordingly, DOE has concluded that it is not necessary to prepare a Family Policymaking Assessment.
Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use”, 66 FR 28355 (May 22, 2001), requires Federal agencies to prepare and submit to the Office of Information and Regulatory Affairs (OIRA), Office of Management and Budget, a Statement of Energy Effects for any significant energy action. A “significant energy action” is defined as any action by an agency that promulgates or is expected to lead to promulgation of a final rule, and that: (1) Is a significant regulatory action under Executive Order 12866, or any successor order; and (2) is likely to have a significant adverse effect on the supply, distribution, or use of energy, or (3) is designated by the Administrator of OIRA as a significant energy action. For any proposed significant energy action, the agency must give a detailed statement of any adverse effects on energy supply, distribution or use should the proposal be implemented, and of reasonable alternatives to the action and their expected benefits on energy supply, distribution and use. Today's rule is not a significant energy action. Accordingly, DOE has not prepared a Statement of Energy Effects.
The Treasury and General Government Appropriations Act, 2001 (44 U.S.C. 3516, note) provides for agencies to review most disseminations of information to the public under implementing guidelines established by each agency pursuant to general guidelines issued by OMB. OMB's guidelines were published at 67 FR 8452 (February 22, 2002), and DOE's guidelines were published at 67 FR 62446 (October 7, 2002). DOE has reviewed today's notice under the OMB and DOE guidelines and has concluded that it is consistent with applicable policies in those guidelines.
Executive Order 13609 of May 1, 2012, “Promoting International Regulatory Cooperation,” requires that, to the extent permitted by law and consistent with the principles and requirements of Executive Order 13563 and Executive Order 12866, each Federal agency shall:
(a) If required to submit a Regulatory Plan pursuant to Executive Order 12866, include in that plan a summary of its international regulatory cooperation activities that are reasonably anticipated to lead to significant regulations, with an explanation of how these activities advance the purposes of Executive Order 13563 and this order;
(b) Ensure that significant regulations that the agency identifies as having significant international impacts are designated as such in the Unified Agenda of Federal Regulatory and Deregulatory Actions, on RegInfo.gov, and on Regulations.gov;
(c) In selecting which regulations to include in its retrospective review plan, as required by Executive Order 13563, consider:
(i) Reforms to existing significant regulations that address unnecessary differences in regulatory requirements between the United States and its major trading partners, consistent with section 1 of this order, when stakeholders provide adequate information to the agency establishing that the differences are unnecessary; and
(ii) Such reforms in other circumstances as the agency deems appropriate; and
(d) For significant regulations that the agency identifies as having significant international impacts, consider, to the extent feasible, appropriate, and consistent with law, any regulatory approaches by a foreign government that the United States has agreed to consider under a regulatory cooperation council work plan.
DOE has reviewed this final rule under the provisions of Executive Order 13609 and determined that the rule complies with all requirements set forth in the order.
The Office of the Secretary of Energy has approved issuance of this final rule.
As required by 5 U.S.C. 801, DOE will report to Congress on the promulgation of this rule prior to its effective date. The report will state that it has been determined that the rule is not a “major rule” as defined by 5 U.S.C. 804(2).
Government procurement.
For reasons set out in the preamble, the DOE is amending Chapter 9 of Title 48 of the Code of Federal Regulations as set forth below.
42 U.S.C. 7101
This subpart implements Department of Energy (DOE) requirements for contractors concerning compliance with U.S. export control laws and regulations.
(a) DOE and its contractors must comply with all applicable U.S. export control laws and regulations.
(b) Export control laws and regulations include, but are not limited to, the Atomic Energy Act of 1954 (42 U.S.C. 2011
(c) Contractors seeking guidance on how to comply with export control laws and regulations should review the illustrative list of laws and regulations set forth in Clause 952.225-71. Contractors also may contact the agencies responsible for administration of export laws or regulations applicable to a particular export (
(d) DOE Contracting Officers will not answer contractor questions regarding how to comply with U.S. export laws and regulations. Contracting Officers should direct contractors to the export laws, regulations, and agencies cited in the Export Clause at section 952.225-71 of this subpart.
(e) It is the contractor's responsibility to comply with all applicable export control laws and regulations. This responsibility exists independent of, and is not established or limited by, this subpart.
The Contracting Officer shall insert the clause at 952.225-71, Compliance with Export Control Laws and Regulations (Export Clause), in all solicitations and contracts.
42 U.S.C. 2201; 2282a; 2282b; 2282c; 42 U.S.C. 7101
As prescribed in 925.7102, use the following clause:
(a) The Contractor shall comply with all applicable export control laws and regulations.
(b) The Contractor's responsibility to comply with all applicable export control laws and regulations exists independent of, and is not established or limited by, the information provided by this clause.
(c) Nothing in the terms of this contract adds to, changes, supersedes, or waives any of the requirements of applicable Federal laws, Executive Orders, and regulations, including but not limited to—
(1) The Atomic Energy Act of 1954 (42 U.S.C. 2011
(2) The Arms Export Control Act (22 U.S.C. 2751
(3) The Export Administration Act of 1979 (50 U.S.C. app. 2401
(4) Trading with the Enemy Act (50 U.S.C. App. 5(b), as amended by the Foreign Assistance Act of 1961);
(5) Assistance to Foreign Atomic Energy Activities (10 CFR part 810);
(6) Export and Import of Nuclear Equipment and Material (10 CFR part 110);
(7) International Traffic in Arms Regulations (ITAR) (22 CFR parts 120 through 130);
(8) Export Administration Regulations (EAR) (15 CFR Parts730 through 774); and
(9) The regulations administered by the Office of Foreign Assets Control of the Department of the Treasury (31 CFR parts 500 through 598).
(d) In addition to the Federal laws and regulations cited above, National Security Decision Directive (NSDD) 189, National Policy on the Transfer of Scientific, Technical, and Engineering Information, establishes a national policy that, to the maximum extent possible, the products of fundamental research shall remain unrestricted. NSDD 189 provides that no restrictions may be placed upon the conduct or reporting of federally funded fundamental research that has not received national security classification, except as provided in applicable U.S. statutes. As a result, contracts confined to the performance of unclassified fundamental research generally do not involve any export-controlled activities.
NSDD 189 does not take precedence over statutes. NSDD 189 does not exempt any research from statutes that apply to export controls such as the Atomic Energy Act, as amended; the Arms Export Control Act; the Export Administration Act of 1979, as amended; or the U.S. International Emergency Economic Powers Act, or regulations that implement parts of those statutes (
(e) The Contractor shall include the substance of this clause, including this paragraph (e), in all solicitations and subcontracts.
42 U.S.C. 2201; 2282a; 2282b; 2282c; 42 U.S.C. 7101
Contracting officers shall insert the clauses at 48 CFR 52.225-1, Buy American Act—Supplies, and 48 CFR 52.225-9, Buy American Act—Construction Materials, in management and operating contracts. The clause at 48 CFR 52.225-1 shall be modified in paragraph (d) of this section by substituting the word “use” for the word “deliver.”
This subpart implements DOE requirements for DOE management and operating contractors concerning compliance with U.S. export control laws and regulations.
(a) DOE and its contractors must comply with all applicable export control laws and regulations.
(b) Export control laws and regulations include, but are not limited to, the Atomic Energy Act of 1954, as amended; the Arms Export Control Act (22 U.S.C. 2751
(c) Contractors seeking guidance on how to comply with export control requirements should review the illustrative list of laws and regulations applicable to the export of unclassified information, materials, technology, equipment or software set forth in clause 970.5225-1. Contractors also may contact the agencies responsible for administration of export laws and regulations applicable to a particular export (
(d) The contracting officer will not answer any questions a contractor may ask regarding how to comply with export regulations. If asked, the contracting officer should direct the contractor to export regulations and agencies cited in the Export Clause at 970.5225-1.
(e) It is the contractor's responsibility to comply with all applicable U.S. export control laws and regulations. This responsibility exists independent of, and is not established or limited by, this subpart.
The Contracting Officer shall insert the clause at 970.5225-1, Compliance with Export Control Laws and Regulations (Export Clause), in all solicitations and contracts.
As prescribed in 970.2571-3, use the following clause:
(a) The Contractor shall comply with all applicable U.S. export control laws and regulations.
(b) The Contractor's responsibility to comply with all applicable laws and regulations exists independent of, and is not established or limited by, the information provided by this clause.
(c) Nothing in the terms of this contract adds to, changes, supersedes, or waives any of the requirements of applicable Federal laws, Executive Orders, and regulations, including but not limited to—
(1) The Atomic Energy Act of 1954, as amended;
(2) The Arms Export Control Act (22 U.S.C. 2751
(3) The Export Administration Act of 1979 (50 U.S.C. app. 2401
(4) Trading with the Enemy Act (50 U.S.C. App. 5(b), as amended by the Foreign Assistance Act of 1961);
(5) Assistance to Foreign Atomic Energy Activities (10 CFR part 810);
(6) Export and Import of Nuclear Equipment and Material (10 CFR part 110);
(7) International Traffic in Arms Regulations (ITAR) (22 CFR parts 120 through 130);
(8) Export Administration Regulations (EAR) (15 CFR parts 730 through 774); and
(9) Regulations administered by the Office of Foreign Assets Control (31 CFR parts 500 through 598).
(d) In addition to the Federal laws and regulations cited above, National Security Decision Directive (NSDD) 189, National Policy on the Transfer of Scientific, Technical, and Engineering Information establishes a national policy that, to the maximum extent possible, the products of fundamental research shall remain unrestricted. NSDD 189 provides that no restrictions may be placed upon the conduct or reporting of federally funded fundamental research that has not received national security classification, except as provided in applicable U.S. statutes. As a result, contracts confined to the performance of unclassified fundamental research generally do not involve any export-controlled activities.
NSDD 189 does not take precedence over statutes. NSDD 189 does not exempt any research from statutes that apply to export controls such as the Atomic Energy Act, as amended; the Arms Export Control Act; the Export Administration Act of 1979, as amended; or the U.S. International Emergency Economic Powers Act; or the regulations that implement those statutes (
(e) The Contractor shall include the substance of this clause, including this paragraph (e), in all solicitations and subcontracts.
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Reopening of public comment period.
On August 19, 2015, the U.S. Department of Energy (DOE) published a notice of proposed rulemaking (NOPR) in the
DOE will accept comments, data, and information in response to the NOPR received no later than November 23, 2015.
Any comments submitted must identify the NOPR for Energy Conservation Standards for Refrigerated Beverage Vending Machines, and provide docket number EERE-2013-BT-STD-0022 and/or regulatory information number (RIN) number 1904-AD00. Comments may be submitted using any of the following methods:
1.
2.
3.
4.
A link to the docket Web page can be found at: [
For further information on how to submit a comment or review other public comments and the docket, contact Ms. Brenda Edwards at (202) 586-2945 or by email:
John Cymbalsky, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies Program, EE-5B, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 287-1692. Email
For legal issues, please contact Ms. Sarah Butler, U.S. Department of Energy, Office of General Counsel, GC-33, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 586-1777. Email:
On August 19, 2015, DOE published a notice of proposed rulemaking (NOPR) in the
DOE received a request from several stakeholders requesting additional time to prepare and submit comments (Docket No. EERE-2013-BT-STD-0022, Royal Vendors, No. 46 at p. 1, NAMA, No. 44 at p. 1, and AMS, No. 43 at p. 1). In response to these requests, DOE is reopening the public comment period to allow interested parties to provide DOE with written comments and data in response to the BVM ECS NOPR.
DOE will consider any comments in response to the BVM ECS NOPR received by midnight of November 23, 2015, and deems any comments received by that time to be timely submitted.
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Reopening of public comment period.
On September 14, 2015, the U.S. Department of Energy (DOE) published a notice of data availability (NODA) in the
DOE will accept comments, data, and information in response to the NODA received no later than November 6, 2015.
Any comments submitted must identify the NODA for Energy Conservation Standards for Residential Furnaces, and provide docket number EERE-2014-BT-STD-0031 and/or regulatory information number (RIN) number 1904-AD20. Comments may be submitted using any of the following methods:
1.
2.
3.
4.
Docket: The docket, which includes
A link to the docket Web page can be found at: [
For further information on how to submit a comment or review other public comments and the docket, contact Ms. Brenda Edwards at (202) 586-2945 or by email:
John Cymbalsky, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies Program, EE-5B, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 287-1692. Email
For legal issues, please contact Ms. Johanna Hariharan, U.S. Department of Energy, Office of General Counsel, GC-33, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 287-6307. Email:
On September 14, 2015, DOE published a notice of data availability (NODA) in the
DOE received a joint request from the American Gas Association (AGA) and the American Public Gas Association (APGA) requesting additional time to prepare and submit comments (Docket No. EERE-2014-BT-STD-0031, AGA/APGA, No. 168 at p. 2). In response to this request, DOE is reopening the public comment period to allow interested parties to provide DOE with written comments and data in response to the RF ECS NODA.
DOE will consider any comments in response to the RF ECS NODA received by midnight of November 6, 2015, and deems any comments received by that time to be timely submitted.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain Airbus Model A300 B4-600, B4-600R, and F4-600R series airplanes, and Model A300 C4-605R Variant F airplanes (collectively called Model A300-600 series airplanes) modified by a particular supplemental type certificate (STC). This proposed AD was prompted by a report of chafing found on the overflow sensor harness of the surge tank, and subsequent contact between the electrical wiring and fuel tank structure. This proposed AD would require a one-time inspection for damage of the outer tank of the overflow sensor harness, and repair if necessary. This proposed AD would also require modification of the sensor harness. We are proposing this AD to prevent chafing of the harness and subsequent contact between the electrical wiring and fuel tank structure, which could result in electrical arcing and a fuel tank explosion.
We must receive comments on this proposed AD by December 7, 2015.
You may send comments using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
For service information identified in this proposed AD, contact Simmonds Precision Products, Inc., A UTC Aerospace Company, 100 Panton Road,
You may examine the AD docket on the Internet at
Marc Ronell, Aerospace Engineer, Boston Aircraft Certification Office, FAA, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7776; fax: 781-238-7170; email:
We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Union, issued EASA Airworthiness Directive 2013-0193, dated August 23, 2013 (referred to after this as the Mandatory Continuing Airworthiness Information, or “the MCAI”), to correct an unsafe condition for all Airbus Model A300 series airplanes and all Model A300-600 series airplanes.
The MCAI corresponds to FAA AD 2015-03-03, Amendment 39-18099 (80 FR 11101, March 2, 2015), which applies to Airbus Model A300 series airplanes and Model A300-600 series airplanes, all serial numbers, except for airplanes modified by supplemental type certificate ST00092BO (
In AD 2015-03-03, Amendment 39-18099 (80 FR 11101, March 2, 2015), we explained that airplanes that have had the in-tank fuel quantity system modified by STC ST00092BO cannot accomplish the actions required by AD 2015-03-03 by using Airbus Service Bulletin A300-28-6109, Revision 01, dated December 20, 2013.
We also stated that we were considering separate rulemaking to require the procedures and compliance time specified in UTC Aerospace Systems Service Bulletin 300723-28-03 (V-1577), dated October 10, 2014, for airplanes modified by STC ST00092BO. We now have determined that further rulemaking is indeed necessary, and this proposed AD follows from that determination.
UTC Aerospace Systems has issued Service Bulletin 300723-28-03 (V-1577), Revision 01, dated July 20, 2015. The service information describes procedures for an inspection for damage of the outer tank of the overflow sensor harness, repair, and modification of the sensor harness. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the
We are proposing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of these same type designs.
This proposed AD would require accomplishing the actions specified in the service information described previously.
We estimate that this proposed AD affects 65 airplanes of U.S. registry.
We also estimate that it would take about 3 work-hours per product to comply with the inspections required by this proposed AD. The average labor rate is $85 per work-hour. Based on these figures, we estimate the cost of this inspection proposed by this AD on U.S. operators to be $16,575, or $255 per product.
We estimate that it takes about 11 work-hours per product to comply with the modification requirements of this AD. The average labor rate is $85 per work-hour. Required parts cost about $100 per product. Based on these figures, we estimate the cost of this modification on U.S. operators to be $67,275, or $1,035 per product.
We have received no definitive data that would enable us to provide cost estimates for the on-condition actions specified in this proposed AD.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify this proposed regulation:
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
3. Will not affect intrastate aviation in Alaska; and
4. Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
We must receive comments by December 7, 2015.
None.
This AD applies to the Airbus airplanes specified in paragraphs (c)(1), (c)(2), (c)(3), and (c)(4) of this AD; certificated in any category; modified by Simmonds Precision Products, Inc., supplemental type certificate (STC) ST00092BO (
(1) Model A300 B4-601, B4-603, B4-620, and B4-622 airplanes.
(2) Model A300 B4-605R and B4-622R airplanes.
(3) Model A300 F4-605R and F4-622R airplanes.
(4) Model A300 C4-605R Variant F airplanes.
Air Transport Association (ATA) of America Code 28, Fuel.
This AD was prompted by a report of chafing found on the overflow sensor harness of the surge tank, and subsequent contact between the electrical wiring and fuel tank structure. We are issuing this AD to prevent chafing of the harness and subsequent contact between the electrical wiring and fuel tank structure, which could result in electrical arcing and a fuel tank explosion.
Comply with this AD within the compliance times specified, unless already done.
Within 12 months after the effective date of this AD: Do the actions required by paragraphs (g)(1), (g)(2), and (g)(3) of this AD, in accordance with the Accomplishment Instructions of UTC Aerospace Systems Service Bulletin 300723-28-03 (V-1577), Revision 01, dated July 20, 2015.
(1) Perform a one-time general visual inspection for damage of the outer tank sensor harness, and if any damage is found on the expando sleeving, before further flight, do a detailed inspection of the underlying wires for exposed conductor wires. If any exposed conductor wire is found, before further flight, replace the outer wing harness assembly.
(2) Install new brackets and re-route the surge tank overflow sensor harness.
(3) Modify the harness protection.
This paragraph provides credit for actions required by paragraph (g) of this AD, if those actions were performed before the effective date of this AD using UTC Aerospace Systems Service Bulletin 300723-28-03 (V-1577), dated October 10, 2014. This service information is not incorporated by reference in this AD.
(1) The Manager, Boston Aircraft Certification Office (ACO) ANE-150, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or local Flight Standards District Office, as appropriate. If sending information directly to the manager of the ACO, send it to the attention of the person identified in paragraph (j)(1) of this AD.
(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.
(1) For more information about this AD, contact Marc Ronell, Aerospace Engineer, Boston ACO, FAA, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7776; fax: 781-238-7170; email:
(2) For service information identified in this AD, contact Simmonds Precision Products, Inc., A UTC Aerospace Company, 100 Panton Road, Vergennes, Vermont 05491; phone 802-877-2911; fax 802-877-4444; Internet
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain Engine Alliance (EA) GP7270 turbofan engines. This proposed AD was prompted by reports of the installation of non-conforming honeycomb seals in the high-pressure compressor (HPC) adjacent to the HPC rotor stage 2 to 5 spool and stage 7 to 9 spool. This proposed AD would require removal and replacement of the affected HPC rotor stage 2 to 5 and stage 7 to 9 spools. We are proposing this AD to prevent failure of the HPC rotor stage 2 to 5 and stage 7 to 9 spools, which could lead to uncontained engine failure and damage to the airplane.
We must receive comments on this proposed AD by December 22, 2015.
You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
•
•
•
•
For service information identified in this proposed AD, contact Engine Alliance, 400 Main St., East Hartford, CT 06108, M/S 169-10, phone: 800-565-0140; email:
You may examine the AD docket on the Internet at
Martin Adler, Aerospace Engineer, Engine & Propeller Directorate, FAA, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7157; fax: 781-238-7199; email:
We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the
We will post all comments we receive, without change, to
We learned from the manufacturer that non-conforming honeycomb seals were installed in the affected HPCs adjacent to the HPC rotor stage 2 to 5 spools and stage 7 to 9 spools. The honeycomb seals in the HPC were machined to an incorrect radial height which resulted in reduced clearances between the honeycomb and the rotating spools. This error could lead to cracks on the spools prior to reaching their full life. This condition, if not corrected, could result in failure of the HPC rotor stage 2 to 5 and stage 7 to 9 spools, which could lead to uncontained engine failure, and damage to the airplane.
Engine Alliance has issued EA Service Bulletin (SB) No. EAGP7-72-327, dated July 21, 2015; and SB No. EAGP7-72-328, dated July 21, 2015. The SBs describe procedures for removal and replacement of HPC rotor stage 2 to 5 spools and HPC rotor stage 7 to 9 spools, respectively. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the
We are proposing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design.
This proposed AD would require removal and replacement of the affected HPC rotor stage 2 to 5 and stage 7 to 9 spools.
We estimate that this proposed AD affects zero engines installed on airplanes of U.S. registry. The average labor rate is $85 per hour. Based on these figures, we estimate the cost of this proposed AD on U.S. operators to be $0.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs, describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify this proposed regulation:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska to the extent that it justifies making a regulatory distinction, and
(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
We must receive comments by December 22, 2015.
None.
This AD applies to Engine Alliance (EA) GP7270 turbofan engines with one or both of the following installed:
(1) A high-pressure compressor (HPC) rotor stage 2 to 5 spool, part number (P/N) 382-104-807-0, with a serial number (S/N) listed in EA Service Bulletin (SB) No. EAGP7-72-327, dated July 21, 2015; or
(2) an HPC rotor stage 7 to 9 spool, P/N 2031M90G04, 2031M90G05, or 2031M90G07, with an S/N listed in EA SB No. EAGP7-72-328, dated July 21, 2015.
This AD was prompted by reports of the installation of non-conforming honeycomb seals in the HPC adjacent to the HPC rotor stage 2 to 5 spool and stage 7 to 9 spool. We are issuing this AD to prevent failure of the HPC rotor stage 2 to 5 spools and stage 7 to 9 spools, which could lead to uncontained engine failure and damage to the airplane.
Comply with this AD within the compliance times specified, unless already done. Within 30 days after the effective date of this AD or before accumulating 2,100 engine cycles since the last disassembly of the compressor module of the engine, whichever occurs later:
(1) For engines with an HPC rotor stage 2 to 5 spool, P/N 382-104-807-0, installed with a S/N listed in EA SB No. EAGP7-72-327, dated July 21, 2015, do the following:
(i) Remove the HPC rotor stage 2 to 5 spool from service and replace with a part eligible for installation.
(ii) Remove and replace the honeycomb seals on the HPC stage 5 vanes.
(2) For engines with an HPC rotor stage 7 to 9 spool, P/N 2031M90G04, 2031M90G05, or 2031M90G07 installed with an S/N listed in EA SB No. EAGP7-72-328, dated July 21, 2015, do the following:
(i) Remove the HPC rotor stage 7 to 9 spool from service and replace with a part eligible for installation.
(ii) Remove and replace the honeycomb seals on the HPC stage 6, stage 7, and stage 8 vanes.
The Manager, Engine Certification Office, may approve AMOCs for this AD. Use the procedures found in 14 CFR 39.19 to make your request. You may email your request to:
(1) For more information about this AD, contact Martin Adler, Aerospace Engineer, Engine & Propeller Directorate, FAA, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7157; fax: 781-238-7199; email:
(2) EA SBs No. EAGP7-72-327, dated July 21, 2015; and No. EAGP7-72-328, dated July 21, 2015 can be obtained from EA using the contact information in paragraph (g)(3) of this proposed AD.
(3) For service information identified in this AD, contact Engine Alliance, 400 Main St., East Hartford, CT 06108, M/S 169-10, phone: 800-565-0140; email:
(4) You may view this service information at the FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA. For information on the availability of this material at the FAA, call 781-238-7125.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to supersede Airworthiness Directive (AD) 2012-18-12, for certain Airbus Model A318, A319, and A320 series airplanes. AD 2012-18-12 currently requires modifying the off-wing escape slide (OWS) enclosures on the left-hand (LH) side and right-hand (RH) side of the fuselage. Since we issued AD 2012-18-12, we have received reports that additional OWS part numbers have been affected. This proposed AD would retain the requirements of AD 2012-18-12 and expand the applicability to all Airbus Model A318, A319, and A320 series airplanes. We are proposing this AD to prevent off-wing exits on the LH and RH sides of the fuselage from becoming inoperative, which, during an emergency, could impair the safe evacuation of occupants, possibly resulting in personal injuries.
We must receive comments on this proposed AD by December 7, 2015.
You may send comments by any of the following methods:
• Federal eRulemaking Portal: Go to
• 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: U.S. Department of Transportation, Docket Operations, M-30, 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.
For Airbus service information identified in this proposed AD, contact Airbus, Airworthiness Office—EIAS, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France; telephone +33 5 61 93 36 96; fax +33 5 61 93 44 51; email
You may examine the AD docket on the Internet at
Sanjay Ralhan, Aerospace Engineer, International Branch, ANM-116, Transport Airplane Directorate, FAA, 1601 Lind Avenue SW., Renton, WA 98057-3356; telephone 425-227-1405; fax 425-227-1149.
We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
On August 31, 2012, we issued AD 2012-18-12, Amendment 39-17189 (77 FR 57003, September 17, 2012). AD 2012-18-12 requires actions intended to address an unsafe condition on certain Airbus Model A318, A319, and A320 series airplanes.
Since we issued AD 2012-18-12, Amendment 39-17189 (77 FR 57003, September 17, 2012), we received reports that additional OWS part numbers have been affected which requires expanding the applicability to all Airbus Model A318, A319, and A320 series airplanes.
The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Union, has issued EASA Airworthiness Directive 2014-0025R1, dated May 26, 2014 (referred to after this as the Mandatory Continuing Airworthiness Information, or “the MCAI”), to correct an unsafe condition on all Airbus Model A318, A319, and A320 series airplanes. The MCAI states:
One operator reported a torn out aspirator during scheduled deployment (for on ground testing purposes) of the Left Hand (LH) off-wing [escape] slide (OWS). Investigation results revealed that the aspirator of the OWS system interfered with the extrusion lip of the OWS enclosure during the initial stage of the deployment sequence.
This condition, if not corrected, could lead to an off-wing exit, either LH or Right Hand (RH), becoming unserviceable, which, during an emergency situation, could impair the safe evacuation of occupants, possibly resulting in personal injuries.
To address this potential unsafe condition, Airbus issued Service Bulletin (SB) A320-25-1649 containing modification instructions for certain part number (P/N) OWS enclosures. Consequently, EASA issued [EASA] AD 2010-0210 [(
Since that [EASA] AD was issued, several other OWS P/N[s] have been identified as potentially impacted.
For the reason described above, this [EASA] AD retains the requirements of EASA AD 2010-0210, which is superseded, expands the Applicability to all A318, A319 and A320 aeroplanes, and expands the batch of affected P/N[s] prohibited to be installed on an aeroplane.
For the reason described above, EASA issued AD 2014-0025, retaining the requirements of EASA AD 2010-0210, which was superseded, expanding the Applicability to all A318, A319 and A320 aeroplanes, and expanding the batch of affected P/N[s] prohibited to be installed on an aeroplane. That [EASA] AD also retained the requirements of * * * [an AD, which was superseded], which required modification of the OWS and its aspirator.
This [EASA] AD is revised to amend paragraphs (1) and (3) to restore the original applicability of DGAC France AD 2001-380 and EASA AD 2010-0210, respectively, and to correct paragraph (2) to give credit for certain production modifications that were equivalent for the in-service actions previously required by DGAC France AD 2001-380.
You may examine the MCAI in the AD docket on the Internet at
Airbus has issued the following service information.
• Airbus Service Bulletin A320-25-1156, Revision 03, dated December 5, 2001. This service information describes procedures for modifying OWS enclosures having part numbers (P/N) D31865-101, D31865-102, D31865-103, D31865-104, D31865-105, D31865-106, D31865-107, or D31865-108 of certain Airbus Model A319 and A320 series airplanes.
• Airbus Service Bulletin A320-25-1265, Revision 01, dated December 5, 2001. This service information describes procedures for modifying and installing the OWS enclosure on the LH and RH sides of the fuselage on certain Airbus Model A319 and A320 series airplanes.
• Airbus Service Bulletin A320-25-1649, dated February 16, 2010. This service information describes procedures for modifying and installing OWS enclosures having part numbers (P/N) D31865-109, D31865-110, D31865-209, or D31865-210, on the LH and RH sides of the fuselage on certain Airbus Model A318, A319, and A320 series airplanes.
Air Cruisers has issued Service Bulletin A320 004-25-84, Revision 4, dated November 9, 2012. This service information describes procedures for modifying LH and RH OWS.
This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the
This product has been approved by the aviation authority of another country, and is approved for operation in the United States. Pursuant to our bilateral agreement with the State of Design Authority, we have been notified of the unsafe condition described in the MCAI and service information referenced above. We are proposing this AD because we evaluated all pertinent information and determined an unsafe condition exists and is likely to exist or develop on other products of the same type design.
We estimate that this proposed AD affects 851 airplanes of U.S. registry.
The actions required by AD 2012-18-12, Amendment 39-17189 (77 FR 57003, September 17, 2012), and retained in this proposed AD take about 14 work-hours per product, at an average labor rate of $85 per work-hour. Required parts cost $0 per product. Based on these figures, the estimated cost of the actions that are required by AD 2012-18-12 is $1,190 per product.
We also estimate that it would take about 48 work-hours per product to comply with the basic requirements of this proposed AD. The average labor rate is $85 per work-hour. Required parts would cost $0 per product. Based on these figures, we estimate the cost of this proposed AD on U.S. operators to be $3,472,080, or $4,080 per product.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and
For the reasons discussed above, I certify this proposed regulation:
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
3. Will not affect intrastate aviation in Alaska; and
4. Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
We must receive comments by December 7, 2015.
This AD replaces (AD) 2012-18-12, Amendment 39-17189 (77 FR 57003, September 17, 2012).
This AD applies to the Airbus airplanes identified in paragraphs (c)(1), (c)(2), and (c)(3) of this AD, certificated in any category, all manufacturer serial numbers.
(1) Model A318-111, -112, -121, and -122 airplanes.
(2) Model A319-111, -112, -113, -114, -115, -131, -132, and -133 airplanes.
(3) Model 320-211, -212, -214, -231, -232, and -233 airplanes.
Air Transport Association (ATA) of America Code 25, Equipment/furnishings.
This AD was prompted by a report of a torn out aspirator due to the aspirator interfering with the extrusion lip of the off-wing escape slide (OWS) enclosure during the initial stage of the deployment sequence. This AD was also prompted by reports that additional OWS part numbers have been affected which requires expanding the applicability to all Airbus Model A318, A319, and A320 series airplanes. We are issuing this AD to prevent off-wing exits on the left-hand (LH) and right-hand (RH) sides of the fuselage from becoming inoperative, which, during an emergency, could impair the safe evacuation of occupants, possibly resulting in personal injuries.
Comply with this AD within the compliance times specified, unless already done.
This paragraph restates the requirements of paragraph (g) of AD 2012-18-12, Amendment 39-17189 (77 FR 57003, September 17, 2012) with no changes. For airplanes equipped with OWS enclosures having part number (P/N) D31865-109, D31865-110, D31865-209, or D31865-210, except as provided by paragraph (i)(1) of this AD: Within 36 months after October 22, 2012, (the effective date of AD 2012-18-12), modify the OWS enclosures and install an OWS enclosure having P/N D31865-309, D31865-311, D31865-310, or D31865-312 on the LH side and RH side of the fuselage, in accordance with the Accomplishment Instructions of Airbus Service Bulletin A320-25-1649, dated February 16, 2010.
For airplanes equipped with an OWS enclosure having P/N D31865-101, D31865-102, D31865-103, D31865-104, D31865-105, D31865-106, D31865-107, or D31865-108, except as provided by paragraph (i)(2) of this AD: Within 36 months after the effective date of this AD, do the actions specified in paragraphs (h)(1) and (h)(2) of this AD.
(1) Modify the OWS enclosures and their aspirators in accordance with the Accomplishment Instructions of Airbus Service Bulletin A320-25-1156, Revision 03, dated December 5, 2001.
(2) Install off-wing escape slides having P/N D31865-109, D31865-110, D31865-209, or D31865-210 on the LH side and RH side of the fuselage, in accordance with the Accomplishment Instructions of Airbus Service Bulletin A320-25-1265, Revision 01, dated December 5, 2001; and accomplish the modification required by paragraph (g) of this AD.
(1) Airplanes having Airbus modification 30088 embodied in production using an OWS enclosure having P/N D31865-111 or D31865-112 are not affected by the requirements of paragraph (g) of this AD, unless a replacement OWS enclosure, having a part number listed in paragraphs (k)(9) through (k)(12) of this AD, has been installed on that airplane since first flight.
(2) Airplanes on which Airbus modifications 24850, 25844, and 27275 have been embodied in production, or on which modifications of the LH and RH OWS enclosures and their aspirators have been accomplished using Airbus Service Bulletin A320-25-1156, Revision 01, dated February 2, 1999, or Revision 2, dated October 26, 1999, and Airbus Service Bulletin A320-25-1265, dated June 6, 2001, are compliant with the modification requirement of paragraph (h) of this AD.
Installing both LH and RH OWS that have been modified in accordance with the Accomplishment Instructions of Air Cruisers Service Bulletin A320 004-25-84, Revision 4, dated November 9, 2012, is an acceptable method of compliance with the modification required by paragraph (g) of this AD.
As of the effective date of this AD, do not install on any airplane an OWS enclosure having a part number listed in paragraphs (k)(1) through (k)(12) of this AD, except as required by paragraph (h)(2) of this AD for the OWS enclosures identified in paragraph (h) of this AD.
(1) This paragraph provides credit for the actions specified in paragraph (h)(1) of this AD, if those actions were performed before the effective date of this AD using the service information identified in paragraph (l)(1)(i) or (l)(1)(ii) of this AD, which is not incorporated by reference.
(i) Airbus Service Bulletin A320-25-1156, Revision 01, dated February 2, 1999.
(ii) Airbus Service Bulletin A320-25-1156, Revision 02, dated October 26, 1999.
(2) This paragraph provides credit for the actions specified in paragraph (h)(2) of this AD, if those actions were performed before the effective date of this AD using Airbus Service Bulletin A320-25-1265, dated June 6, 2001, which is not incorporated by reference.
(3) This paragraph provides credit for the actions specified in paragraph (j) of this AD, if those actions were performed before the effective date of this AD using the service information identified in paragraph (l)(3)(i), (l)(3)(ii), (l)(3)(iii), or (l)(3)(iv) of this AD, which is not incorporated by reference.
(i) Air Cruisers Service Bulletin A320 004-25-84, dated February 5, 2010.
(ii) Air Cruisers Service Bulletin A320 004-25-84, Revision 1, dated April 9, 2010.
(iii) Air Cruisers Service Bulletin A320 004-25-84, Revision 2, dated February 11, 2011.
(iv) Air Cruisers Service Bulletin A320 004-25-84, Revision 3, dated October 28, 2011.
The following provisions also apply to this AD:
(1)
(i) 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. The AMOC approval letter must specifically reference this AD.
(ii) AMOCs approved previously for AD 2012-18-12, Amendment 39-17189 (77 FR 57003, September 17, 2012), are approved as AMOCs for the corresponding provisions of paragraph (g) of this AD.
(2)
(1) Refer to Mandatory Continuing Airworthiness Information (MCAI) European Aviation Safety Agency (EASA) Airworthiness Directive 2014-0025R1, dated May 26, 2014, for related information. This MCAI may be found in the AD docket on the Internet at
(2) For Airbus service information identified in this AD, contact Airbus, Airworthiness Office—EIAS, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France; telephone +33 5 61 93 36 96; fax +33 5 61 93 44 51; email
Internal Revenue Service (IRS), Treasury.
Notice of proposed rulemaking.
This document contains proposed regulations that reflect the holdings of
Written or electronic comments and requests for a public hearing must be received by December 7, 2015.
Send submissions to: CC:PA:LPD:PR (REG-148998-13), Room 5205, Internal Revenue Service, P.O. Box 7604, Ben Franklin Station, Washington, DC 20044. Submissions may be hand-delivered Monday through Friday between the hours of 8 a.m. and 4 p.m. to CC:PA:LPD:PR (REG-148998-13), Courier's Desk, Internal Revenue Service, 1111 Constitution Avenue NW., Washington, DC; or sent electronically via the Federal eRulemaking Portal at
Concerning the proposed amendments to the regulations, Mark Shurtliff at (202) 317-3400; concerning submissions of comments and requests for a hearing, Regina Johnson at (202) 317-6901 (not toll-free numbers).
This document contains proposed amendments to the Income Tax Regulations (26 CFR part 1), the Estate Tax Regulations (26 CFR part 20), the Gift Tax Regulations (26 CFR part 25), the Generation-Skipping Transfer Tax Regulations (26 CFR part 26), the Employment Tax and Collection of Income Tax at Source Regulations (26 CFR part 31), and the Regulations on Procedure and Administration (26 CFR part 301).
On June 26, 2013, the Supreme Court in
In light of the holdings of
In addition, these proposed regulations provide that a marriage of two individuals will be recognized for federal tax purposes if that marriage would be recognized by any state, possession, or territory of the United States. Under this rule, whether a marriage conducted in a foreign jurisdiction will be recognized for federal tax purposes depends on whether that marriage would be recognized in at least one state, possession, or territory of the United States. This comports with the general principles of comity where countries recognize actions taken in foreign jurisdictions, but only to the extent those actions do not violate their own laws. See
Although these proposed regulations define terms relating to marital status for federal tax purposes, the IRS may provide additional guidance as needed. For example, the IRS has already issued more particular guidance for employers regarding the application of Revenue Ruling 2013-17 to qualified retirement plans, and that guidance remains in effect. See Notice 2014-19 (2014-47 IRB 979).
For federal tax purposes, the term “marriage” does not include registered domestic partnerships, civil unions, or other similar relationships recognized under state law that are not denominated as a marriage under that state's law, and the terms “spouse,” “husband and wife,” “husband,” and “wife” do not include individuals who have entered into such a relationship.
Except when prohibited by statute, the IRS has traditionally looked to the states to define marital status. See
Some couples have chosen to enter into a civil union or registered domestic partnership even when they could have married, and some couples who are in a civil union or registered domestic partnership have chosen not to convert those relationships into a marriage even when they have had the opportunity to do so. In many cases, this choice was deliberate, and couples who enter into civil unions or registered domestic partnerships may have done so with the expectation that their relationship will not be treated as a marriage for purposes of federal law. For some of these couples, there are benefits to being in a relationship that provides some, but not all, of the protections and responsibilities of marriage. For example, some individuals who were previously married and receive Social Security benefits as a result of their previous marriage may choose to enter into a civil union or registered domestic partnership (instead of a marriage) so that they do not lose their Social Security benefits. More generally, the rates at which some couples' income is taxed may increase if they are considered married and thus required to file a married-filing-separately or married-filing-jointly federal income tax return. Treating couples in civil unions and registered domestic partnerships the same as married couples who are in a relationship denominated as marriage under state law could undermine the expectations certain couples have regarding the scope of their relationship. Further, no provision of the Code indicates that Congress intended to recognize as marriages civil unions, registered domestic partnerships, or similar relationships. Accordingly, the IRS will not treat civil unions, registered domestic partnerships, or other similar relationships as marriages for federal tax purposes.
These proposed regulations would, as of the date they are published as final regulations in the
The regulations, as proposed, would be applicable as of the date of publication of a Treasury decision adopting these rules as final regulations in the
For copies of recently issued Revenue Procedures, Revenue Rulings, Notices, and other guidance published in the Internal Revenue Bulletin, please visit the IRS Web site at
Certain IRS regulations, including this one, are exempt from the requirements of Executive Order 12866, as supplemented and reaffirmed by Executive Order 13563. Therefore, a regulatory impact assessment is not required. It has also been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply to these regulations. In addition, because the regulations do not impose a collection of information on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply. Accordingly, a regulatory flexibility analysis is not required under the Regulatory Flexibility Act (5 U.S.C. chapter 6). Pursuant to section 7805(f) of the Code, this notice of proposed rulemaking will be submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on its impact on small businesses.
Before these proposed regulations are adopted as final regulations,
The principal author of these proposed regulations is Mark Shurtliff of the Office of the Associate Chief Counsel, Procedure and Administration.
Income taxes, Reporting and recordkeeping requirements.
Estate taxes, Reporting and recordkeeping requirements.
Gift taxes, Reporting and recordkeeping requirements.
Estate, Reporting and recordkeeping requirements.
Employment taxes, Income taxes, Penalties, Pensions, Reporting and recordkeeping requirements, Social Security, Unemployment compensation.
Employment taxes, Estate taxes, Excise taxes, Gift taxes, Income taxes, Penalties, Reporting and recordkeeping requirements.
Accordingly, 26 CFR parts 1, 20, 25, 26, 31, and 301 are proposed to be amended as follows:
26 U.S.C. 7805 * * *
(a)
(b)
26 U.S.C. 7805 * * *
(a)
(b)
26 U.S.C. 7805 * * *
(a)
(b)
26 U.S.C. 7805 * * *
(a)
(b)
26 U.S.C. 7805 * * *
(a)
(b)
26 U.S.C. 7805 * * *
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Environmental Protection Agency.
Proposed rule.
The Environmental Protection Agency (EPA) is proposing to approve into Oregon's State Implementation Plan (SIP) a submittal from the Oregon Department of Environmental Quality (ODEQ) dated July 7, 2014, containing revisions to the Lane Regional Air Protection Agency's (LRAPA) open burning rules adopted on March 14, 2008. The revised LRAPA open burning rules make clarifications and provide for additional controls of open burning activities in Lane County, would reduce particulate emissions in Lane County, and would strengthen Oregon's SIP. The EPA is also proposing to approve a submittal from the ODEQ dated June 30, 2014, to update Oregon Administrative Rules (OAR) that relate to procedures in contested cases (appeals), enforcement procedures, and civil penalties. The EPA is proposing to approve most of the submitted provisions because the revisions clarify and strengthen the SIP and are consistent with the Clean Air Act (CAA). The EPA is not proposing to approve certain provisions of the submitted rules that do not relate to the requirements for SIPs under section 110 of the CAA. Finally, the EPA is proposing to correct the SIP pursuant to the authority of section 110(k)(6) of the CAA to remove certain provisions previously approved by the EPA that do not relate to the requirements for SIPs under section 110 of the CAA.
Comments must be received on or before November 23, 2015.
Submit your comments, identified by Docket ID No. EPA-R10-OAR-2014-0562, by any of the following methods:
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Please see the direct final rule which is located in the Rules section of this
Keith Rose at telephone number: (206) 553-1949, email address:
For further information, please see the direct final action, of the same title, which is located in the Rules section of this
If the EPA receives adverse comments, the EPA will withdraw the direct final rule and it will not take effect. The EPA will address all public comments in a subsequent final rule based on this proposed rule. The EPA will not institute a second comment period on this action. Any parties interested in commenting on this action should do so at this time. Please note that if we receive adverse comment on an amendment, paragraph, or section of this rule and if that provision may be severed from the remainder of the rule, the EPA may adopt as final those provisions of the rule that are not the subject of an adverse comment.
Federal Communications Commission.
Petition for reconsideration.
Petitions for Reconsideration (Petitions) have been filed in the Commission's Rulemaking Proceeding by Ari Q. Fitzgerald, on behalf of GE Healthcare; Ronald J. Bruno on behalf of The VideoHouse, Inc.; Benjamin Perez on behalf of Abacus Television; Lawrence Rogow on behalf of WMTM, LLC; and Larry E. Morton on behalf of KMYA, LLC.
Oppositions to the Petitions must be filed on or before November 9, 2015. Replies to an opposition must be filed on or before November 17, 2015.
Federal Communications Commission, 445 12th Street SW., Washington, DC 20554.
Joyce Bernstein, Media Bureau, (202) 418-1647, email:
This is a summary of Commission's document, Report No. 3028, released September 21, 2015. The full text of the Petitions is available for viewing and copying in Room CY-B402, 445 12th Street SW., Washington, DC 20554 or may be accessed online via the Commission's Electronic Comment Filing System at
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of decision on petition for rulemaking; advance notice of proposed rulemaking; request for comments.
This document includes two distinct but related NMFS actions. First, NMFS announces that it has denied a petition for rulemaking from Tri Marine Management Company, LLC, related to purse seine fishing effort limits in the area of competence of the Commission for the Conservation and Management of Highly Migratory Fish Stocks in the Western and Central Pacific Ocean (Commission). Second, NMFS issues an advance notice of proposed rulemaking related to the treatment of U.S.-flagged purse seine vessels and their fishing activities in regulations implementing decisions of the Commission.
Comments on this advance notice of proposed rulemaking must be submitted in writing by November 23, 2015.
The notice of receipt of the petition for rulemaking, the petition, and the public comments on the petition are available via the Federal e-Rulemaking Portal at
NMFS is not requesting comments on the notice of decision on the petition.
You may submit comments on the advance notice of proposed rulemaking, identified by NOAA-NMFS-2015-0128, by either of the following methods:
•
1. Go to
2. Click the “Comment Now!” icon, complete the required fields, and
3. Enter or attach your comments.
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Tom Graham, NMFS PIRO, 808-725-5032.
The Convention on the Conservation and Management of Highly Migratory Fish Stocks in the Western and Central Pacific Ocean (Convention) focuses on the conservation and management of highly migratory species (HMS) and the management of fisheries for HMS. The objective of the Convention is to ensure, through effective management, the long-term conservation and sustainable use of HMS in the WCPO. To accomplish this objective, the Convention established the Commission, which includes Members, Cooperating Non-members, and Participating Territories. The United States of America is a Member. American Samoa, Guam, and the Commonwealth of the Northern Mariana Islands are Participating Territories.
As a Contracting Party to the Convention and a Member of the Commission, the United States implements domestically conservation and management measures adopted by the Commission and other decisions of the Commission. The Western and Central Pacific Fisheries Convention Implementation Act (16 U.S.C. 6901
Since 2009, NMFS regulations have established limits on fishing effort by U.S. purse seine fishing vessels in the area of application of the Convention (Convention Area), including in the area known as the Effort Limit Area for Purse Seine, or ELAPS, which is comprised of all areas of high seas and the U.S. exclusive economic zone (EEZ) between the latitudes of 20° N. and 20° S. in the Convention Area. These regulations are promulgated under authority of the WCPFC Implementation Act and have been codified at 50 CFR 300.223(a).
NMFS has established the purse seine fishing effort limits in the ELAPS to implement a series of Commission decisions for tropical tuna stocks in the Convention Area.
NMFS established a purse seine fishing effort limit in the ELAPS for 2015 in an interim rule published May 21, 2015 (80 FR 29220). NMFS issued a final rule, responding to comments on the interim rule and making final the interim rule, on August 25, 2015 (80 FR 51476). The limit is 1,828 fishing days.
On June 8, 2015, NMFS issued a notice announcing that the U.S. purse seine fishery in the ELAPS would close as a result of reaching the limit of 1,828 fishing days (80 FR 32313). The closure took effect June 15, 2015, and will remain in effect through December 31, 2015. The closure applies to all U.S. purse seine fishing vessels. During the closure, fishing vessels of the United
Under the Administrative Procedure Act, interested persons may petition Federal agencies for the issuance, amendment, or repeal of a rule.
As described further below, NMFS received such a petition from Tri Marine Management Company, LLC (Tri Marine). On July 17, 2015, NMFS issued a notice of receipt of the petition and a request for comments on the petition (80 FR 42464). The comment period ended August 17, 2015.
In a petition dated May 12, 2015, Tri Marine requested that NMFS take two actions. First, Tri Marine requested that “NOAA undertake an emergency rulemaking with respect to the 2015 ELAPS limits for fishing days on the high seas.” Second, Tri Marine requested that “NOAA issue a rule exempting from that high seas limit any US flag purse seine vessel which, pursuant to contract or declaration of intent, delivers or will deliver at least 50 percent of its catch to tuna processing facilities based in American Samoa.”
At the time of Tri Marine's initial request, NMFS was preparing to issue an interim rule establishing a limit on purse seine fishing effort in the ELAPS for 2015. As described above, NMFS established a limit in the ELAPS for 2015 in an interim rule published May 21, 2015. Accordingly, the first part of Tri Marine's request has been fully addressed and is not further discussed in this notice. NMFS acknowledged that it had received Tri Marine's petition for rulemaking in the May 21, 2015, interim rule, and stated that it would consider and respond to the petition separately.
With regard to the second part of Tri Marine's request, the petition explains that as a result of decisions by the Republic of Kiribati, U.S. purse seine vessels' access to their traditional fishing grounds in 2015 has been dramatically reduced, and that the high seas portion of the ELAPS can be expected to be closed to fishing as early as June. The petition further states that because of the limited fishing grounds now available to the American Samoa-based purse seine fleet and other factors, including an unusually low tuna price and the higher cost of access to fishing grounds in the region, the ability of American Samoa-based tuna vessels to operate profitably is in serious question, and the loss of a reliable supply of tuna from these vessels will jeopardize the ability of the canneries in American Samoa to compete in world markets. The petition states that under the Convention, American Samoa is afforded special treatment as a small island developing state or participating territory for purposes of applying conservation and management measures of the Commission, and therefore NMFS should develop rules that exempt from the ELAPS limit those vessels that deliver at least 50 percent of their catch to the canneries in American Samoa.
The petition includes further information on the basis of the request, including information related to the recommendations of the Governor of American Samoa's Fisheries Task Force, and an “issue brief” with statements about the nature of the issue and how the requested rule(s) would address it.
In a second letter to NMFS dated May 26, 2015, which supplements the May 12, 2015, petition, Tri Marine acknowledged the interim rule published May 21, 2015, and amended its request to include the U.S. EEZ. Tri Marine requested that “NOAA undertake an emergency rulemaking with respect to the 2015 ELAPS limits for fishing days (both) on the high seas and in the US EEZ,” and further requested that “NOAA issue a rule exempting from the ELAPS limits any US flag purse seine vessel which, pursuant to contract or declaration of intent, delivers or will deliver at least 50 percent of its catch to tuna processing facilities based in American Samoa.”
NMFS received comments on the petition from about 100 parties, including individuals employed in fish processing facilities in American Samoa and their families and friends; owners, operators and crew members of U.S. purse seine vessels; owners and operators of fish processing facilities in American Samoa; other businesses doing business in American Samoa; non-governmental organizations; and government officials of American Samoa and the United States. Most comments were in favor of the petition. Those in favor cited what they believed are adverse economic impacts of the 2015 ELAPS limit on purse seine fishing businesses, on fish processing facilities and other businesses in American Samoa, on employment in those businesses, and on the American Samoa economy in general. The comments in opposition to the petition argued that the requested action would unfairly favor certain businesses in the U.S. purse seine fishery over others and would be inconsistent with the Convention and the decisions of the Commission.
After considering the petition and the public comments on the petition, NMFS finds that it is not appropriate to grant the petitioner's request to issue a rule exempting from the 2015 ELAPS limit any U.S.-flagged purse seine vessel which, pursuant to contract or declaration of intent, delivers or will deliver at least 50 percent of its catch to tuna processing facilities based in American Samoa. As described in the regulatory impact review prepared for the rule to establish the 2015 ELAPS limit, NMFS found that the limit is expected to have substantial adverse economic impacts on U.S. purse seine fishing businesses in the WCPO, and also that adverse impacts in terms of income and employment could occur in business sectors with backward and forward linkages to the producers. These sectors could include businesses that supply the purse seine fishing vessels, and the fish processing facilities in American Samoa. However, to sufficiently assess whether such impacts, or other circumstances, warrant the regulatory action requested by the petition would require additional information that is not readily available to NMFS, as well as sufficient time to examine such information. In particular, NMFS does not have information that demonstrates that the 2015 ELAPS limit will adversely impact American Samoa's fish processing facilities and its economy in the manner alleged by the petitioner. The petitioner argues that lacking the requested regulatory action, the ability of the American Samoa-based purse seine fleet to operate profitably would be in serious question, and the loss of a reliable supply of tuna from those vessels would jeopardize the ability of the canneries in American Samoa to compete in world markets with lower-cost competitors, and further, that tuna landings and processing are essential to the overall economic health of American Samoa.
NMFS has received some relevant information in the public comments on the petition, and NMFS intends to collect additional economic and other information. However, NMFS does not yet have sufficient information to determine whether the 2015 ELAPS limit is likely to jeopardize the ability of the American Samoa canneries to compete in world markets, or to determine how the loss of such competitiveness would affect American Samoa's overall economy. Moreover, if the 2015 ELAPS limit is found to impact American Samoa's fish processing facilities and its economy in the manner alleged in the petition, NMFS would
Although NMFS has denied the petition, NMFS acknowledges that some of the issues raised in the petition warrant further examination. As described in the following section, NMFS intends to more fully examine the problems raised by the petitioner and by commenters on the petition. If the findings of that examination confirm a problem that—given U.S. obligations under the Convention and other applicable laws—warrants corrective action, NMFS would consider further rulemaking. At this time, however, NMFS cannot predict the timing or provisions of any future proposed or final rule.
Under the WCPFC Implementation Act, NMFS exercises broad discretion when determining how it implements Commission decisions, such as purse seine fishing restrictions. NMFS intends to examine the potential impacts of the domestic implementation of Commission decisions for purse seine fisheries on the economies of the U.S. Participating Territories, and examine the connectivity between the activities of U.S.-flagged purse seine fishing vessels and the economies of the territories. Based on those findings, NMFS will consider proposing regulations that mitigate adverse economic impacts of purse seine fishing restrictions on the U.S. Participating Territories, to the extent consistent with U.S. obligations under the Convention. Also, NMFS is considering proposing regulations that recognize that in the context of the Convention, one or more of the U.S. Participating Territories have their own purse seine fisheries that are distinct from the purse seine fishery of the United States. In that case, the purse seine fisheries of the U.S. Participating Territories might be subject to special provisions of the Convention and of Commission decisions, and NMFS would implement those provisions and decisions accordingly.
NMFS notes that the Tri Marine petition focused on the 2015 ELAPS limit. This advanced notice of proposed rulemaking is broader in scope, and could apply to other types of restrictions on purse seine fishing that are adopted by the Commission.
In summary, NMFS provides notice that it is considering proposing a rule that would establish rules and/or procedures to address the treatment of U.S.-flagged purse seine vessels and their fishing activities and how they relate to the U.S. Participating Territories in regulations issued by NMFS that implement decisions of the Commission.
NMFS solicits comments on this advance notice of proposed rulemaking. NMFS is particularly interested in receiving any information that would be helpful in assessing the impacts of Commission decisions for purse seine fisheries—as implemented domestically—on the economies of the U.S. Participating Territories, and any information that demonstrates connections between the U.S. Participating Territories and U.S.-flagged purse seine vessels and their fishing activities.
This advance notice of proposed rulemaking has been determined to be not significant for the purposes of Executive Order 12866.
16 U.S.C. 6901
The Department of Agriculture will submit the following information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13 on or after the date of publication of this notice. Comments regarding (a) whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) the accuracy of the agency's estimate of burden including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), New Executive Office Building, Washington, DC; New Executive Office Building, 725 17th Street NW., Washington, DC, 20503. Commenters are encouraged to submit their comments to OMB via email to:
Comments regarding these information collections are best assured of having their full effect if received by November 23, 2015. Copies of the submission(s) may be obtained by calling (202) 720-8681.
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such persons are not required to respond to the collection of information unless it displays a currently valid OMB control number.
Animal and Plant Health Inspection Service, USDA.
Revision to and extension of approval of an information collection; comment request.
In accordance with the Paperwork Reduction Act of 1995, this notice announces the Animal and Plant Health Inspection Service's intention to request a revision to and extension of approval of an information collection associated with importation of citrus from Peru.
We will consider all comments that we receive on or before December 22, 2015.
You may submit comments by either of the following methods:
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Supporting documents and any comments we receive on this docket may be viewed at
For information on the importation of citrus from Peru, contact Mr. Juan (Tony) Román, Senior Regulatory Policy Specialist, RCC, IRM, PHP, PPQ, APHIS, 4700 River Road Unit 156, Riverdale, MD 20737; (301) 851-2242. For copies of more detailed information on the information collection, contact Ms. Kimberly Hardy, APHIS' Information Collection Coordinator, at (301) 851-2727.
In accordance with § 319.56-41, the citrus (grapefruit, limes, mandarins or tangerines, sweet oranges, and tangelos) from Peru is subject to certain conditions before entering the continental United States to prevent the introduction of plant pests into the United States. The regulations require the use of information collection activities, including inspections by national plant protection organization (NPPO) officials from Peru, grower registration and agreement, fruit fly trapping, monitoring, recordkeeping, and a phytosanitary certificate.
Since the last approval of this collection, we have adjusted the estimates of burden to more accurately reflect the number of grower registrations and agreements, the number of hours for recordkeeping, the number of respondents for phytosanitary certificates, and to account for activities that were omitted from the last collection (fruit fly management program, reinstatement of production sites, permits, and certification and recertification of cold treatment carriers).
We are asking the Office of Management and Budget (OMB) to approve our use of these information collection activities, as described, for an additional 3 years.
The purpose of this notice is to solicit comments from the public (as well as affected agencies) concerning our information collection. These comments will help us:
(1) Evaluate whether the collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of our estimate of the burden of the collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, through use, as appropriate, of automated, electronic, mechanical, and other collection technologies;
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 record.
Animal and Plant Health Inspection Service, USDA.
Notice.
We are advising the public of our decision to authorize the importation of fresh pitahaya fruit from Israel into the continental United States. Based on the findings of the pest risk analysis, which we made available to the public to review and comment through a previous notice, we have concluded that the application of one or more designated phytosanitary measures will be sufficient to mitigate the risks of introducing or disseminating plant pests or noxious weeds via the importation of fresh pitahaya fruit from Israel.
Effective October 23, 2015.
Mrs. Nicole Russo, Assistant Director, Imports, Regulations, and Manuals, PPQ, APHIS, 4700 River Road Unit 133, Riverdale, MD 20737-1231; (301) 851-2159.
Under the regulations in “Subpart—Fruits and Vegetables” (7 CFR 319.56-1 through 319.56-73, referred to below as the regulations), the Animal and Plant Health Inspection Service (APHIS) prohibits or restricts the importation of fruits and vegetables into the United States from certain parts of the world to prevent plant pests from being introduced into or disseminated within the United States.
Section 319.56-4 of the regulations contains a performance-based process for approving the importation of commodities that, based on the findings of a pest risk analysis, can be safely imported subject to one or more of the designated phytosanitary measures listed in paragraph (b) of that section. Under that process, APHIS publishes a notice in the
In accordance with that process, we published a notice
We solicited comments on the PRA and RMD for 60 days ending on June 29, 2015. We did not receive any comments by that date.
Therefore, in accordance with § 319.56-4(c)(2)(ii), we are announcing our decision to authorize the importation of fresh pitahaya fruit from Israel into the continental United States subject to the following phytosanitary measures:
• The pitahaya must be imported into the continental United States in commercial consignments only.
• Each consignment of pitahaya must be accompanied by a phytosanitary certificate issued by the national plant protection organization of Israel.
• Each consignment of pitahaya is subject to inspection upon arrival at the port of entry to the United States.
These conditions will be listed in the Fruits and Vegetables Import Requirements database (available at
7 U.S.C. 450, 7701-7772, and 7781-7786; 21 U.S.C. 136 and 136a; 7 CFR 2.22, 2.80, and 371.3.
Animal and Plant Health Inspection Service, USDA.
Notice.
We are adding Croatia to the lists of regions that are considered free of foot-and-mouth disease, rinderpest, and swine vesicular disease, and to the list of regions considered free or low risk for classical swine fever. We are taking this action because we have determined that this region is free of foot-and-mouth disease, rinderpest, and swine vesicular disease, and is low risk for classical swine fever. This action establishes the disease status of Croatia with regard to foot-and-mouth disease, rinderpest, swine vesicular disease, and classical swine fever while continuing to protect the United States from an introduction of those diseases.
Effective November 23, 2015.
Mr. Donald Link, Import Risk Analyst, Regionalization Evaluation Services, National Import Export Services, Veterinary Services, APHIS, 920 Main Campus Drive, Suite 200, Raleigh, NC 27606; (919) 855-7731;
The regulations in 9 CFR part 94 (referred to below as the regulations) govern the importation of certain animals and animal products into the United States to prevent the introduction of various animal diseases, including classical swine fever (CSF), foot-and-mouth disease (FMD), rinderpest, and swine vesicular disease (SVD). The regulations prohibit or restrict the importation of live ruminants and swine, and products from these animals, from regions where these diseases are considered to exist.
Within part 94, § 94.1 contains requirements governing the importation of ruminants and swine from regions where rinderpest or FMD exists and the importation of the meat of any ruminants or swine from regions where rinderpest or FMD exists to prevent the introduction of either disease into the United States. We consider rinderpest and FMD to exist in all regions except those listed in accordance with paragraph (a) of that section as free of rinderpest and FMD. Section 94.9 contains requirements governing the importation of pork and pork products from regions where CSF exists. Section 94.10 contains importation requirements for swine from regions where CSF is considered to exist and designates the Animal and Plant Health Inspection Service (APHIS)-defined European CSF region as a single region of low-risk for CSF. Section 94.31 contains requirements governing the importation of pork, pork products, and swine from the APHIS-defined European CSF region. We consider CSF to exist in all regions of the world except those listed in accordance with paragraph (a) of § 94.9 as free of the disease.
Section 94.11 of the regulations contains requirements governing the importation of meat of any ruminants or swine from regions that have been determined to be free of rinderpest and FMD, but that are subject to certain restrictions because of their proximity to or trading relationships with rinderpest- or FMD-affected regions. Such regions are listed in accordance with paragraph (a) of that section.
Section 94.12 of the regulations contains requirements governing the importation of pork or pork products from regions where SVD exists. We consider SVD to exist in all regions of the world except those listed in accordance with paragraph (a) of that section as free of SVD.
Section 94.13 contains importation requirements governing the importation of pork or pork products from regions that have been declared free of SVD as provided in § 94.12(a) but supplement their national pork supply by the importation of fresh (chilled or frozen) meat of animals from regions where SVD is considered to exist, or have a common border with such regions, or have trade practices that are less restrictive than are acceptable to the United States. Such regions are listed in accordance with paragraph (a) of § 94.13.
Section 94.14 states that no swine which are moved from or transit any region in which SVD is known to exist may be imported into the United States except wild swine imported in accordance with § 94.14(b).
The regulations in 9 CFR part 92, § 92.2, contain requirements for requesting the recognition of the animal health status of a region (as well as for the approval of the export of a particular type of animal or animal product to the United States from a foreign region). If, after review and evaluation of the
In accordance with that process, on February 3, 2015, we published in the
In addition, we determined in our evaluation that Croatia is low risk for CSF and therefore eligible to be added to the APHIS-defined European CSF region. This region is subject to the conditions in § 94.31 for pork, pork products, and swine and § 98.38 for swine semen. We also determined that the provisions of § 94.11 for import conditions for meat or meat products from ruminants or swine from FMD-free regions, and § 94.13 for import conditions for pork or pork products from SVD-free regions, are applicable to Croatia.
With respect to rinderpest, the global distribution of the disease has diminished significantly in recent years as a result of the Food and Agriculture Organization Global Rinderpest Eradication Program. The last known cases of rinderpest worldwide occurred in the southern part of the “Somali pastoral ecosystem” consisting of southern Somalia, eastern Kenya, and southern Ethiopia. In May 2011, the World Organization for Animal Health (OIE) announced its recognition of global rinderpest freedom.
We solicited comments on the notice of availability for 60 days ending on April 6, 2015. We received two comments by that date, both from national pork industry associations. Both commenters raised specific concerns about disease risks regarding our proposed action to recognize Croatia as being free of FMD, rinderpest, and SVD, and low risk for CSF, as this action would allow for the importation into the United States of swine, pork, and pork products from Croatia subject to the regulations. The comments are discussed below.
The commenters noted that international passenger traffic was identified in the APHIS evaluation as a key risk factor for the introduction of the disease hazards. The commenters stated that limited data exists to determine the quantity of prohibited products smuggled into Croatia and that APHIS obtained estimates of international passenger traffic from 2006 data that is no longer current. The commenters requested that we require Croatia to provide updated information on passenger traffic in order to determine if the risk evaluation needs to be modified.
We agree with the commenter that limited data exists regarding smuggling of prohibited products into Croatia. Such data is by its nature limited because the intent of smuggling is to avoid disclosure, documentation, or inspection. We also acknowledge the volume of international passenger traffic into Croatia and agree that the introduction of prohibited products into Croatia could play a role in the transmission of animal diseases. As the commenters requested, we have provided more recent data for passenger traffic into Croatia.
Data available from the World Bank indicates that 9,111,000, 9,927,000, and 10,369,000 international inbound tourists (overnight visitors) entered Croatia in 2010, 2011, and 2012, respectively.
While the above data indicates that Croatia has seen an increase in the number of international arrivals over the period indicated, the data does not change our conclusions in the risk evaluation. The updated number of arrivals does not differ substantially from the 2006 number we used in the risk evaluation. Additionally, the primary countries of origin listed in Table 1 for arriving passengers are other European Union (EU) Member States that APHIS recognizes to be free of FMD and rinderpest and low risk for CSF. Germany, Slovenia, Austria, and the Czech Republic are also free of SVD, as are several regions of Italy. We determined in the Croatia risk evaluation and previous swine disease status assessments of the EU and individual Member States that the animal health rules governing trade and travel between Member States mitigate the risk of contagious animal disease transmission through international passenger traffic.
We conclude that the risk of virus introduction into Croatia via the pathway of intentionally smuggled or unintentionally carried prohibited products is effectively mitigated by implementing EU-level and Croatian national policies regarding commodities for personal consumption and by the interdiction efforts of Croatia's Border Veterinary Inspection and International
The commenters stated concerns over the ability of commercial swine operations in Croatia to conduct surveillance for and detect foreign animal diseases. As evidence, the commenters cited in the risk evaluation a reference to an interview we conducted with the operator of a company-owned swine fattening farm, in which the operator seemed more aware of potential production impacts than on the clinical signs that would accompany an outbreak of CSF or SVD. The commenters asked if APHIS is confident that the level of awareness of swine operations in Croatia is sufficient for early detection of trade-limiting foreign animal diseases of swine. They recommended that prior to announcing a decision on Croatia's disease status, we should require Croatia to provide us with verification that the industry has been provided with the training or educational materials necessary to assist in active disease surveillance.
We reply that APHIS is confident in the level of awareness for swine diseases in Croatia's commercial swine operations. This particular commercial fattening farm represents Croatia's high intensity, high biosecurity, vertically integrated production and marketing system. Given the advanced swine husbandry standards, premises monitoring by company veterinarians, swine disease training, awareness and sampling, APHIS considers it highly likely that a trade-limiting swine disease in Croatia would be quickly detected and contained. Additionally, we consider Croatia's commercial swine production system to be the most likely source of pork or pork products for export to the United States, and consider the risk of undetected CSF-, FMD-, or SVD-contaminated products being sourced from this production chain to be low.
Regarding this particular commercial farm and farm operator, despite the observation the commenters cited in the risk evaluation, the same farm operator seemed knowledgeable of farm operations, company procedures, and Croatian veterinary and legal requirements. As noted on page 43 of the risk evaluation, we also observed evidence of strong operational, biosecurity, and recordkeeping practices on that farm, as well as strong veterinary oversight. State veterinary authorities reported that the farm receives educational information distributed by Croatia's Ministry of Agriculture, Fisheries, and Rural Development (MAFRD) and that company officials have attended swine disease symposia organized by the MAFRD Veterinary Directorate, which is the central competent authority for animal health and veterinary services in Croatia. In addition, a company veterinarian visits the premises every 2 weeks on average or when called to provide veterinary care. We also observed that the authorized veterinarian for this farm visits regularly to issue health certificates and movement documents.
Overall, our Croatia risk evaluation determined that Croatia has an effective surveillance system in place for detection of swine diseases, including surveillance strategies for the commercial swine sector. We agree with the commenters that early disease detection is a core element of all trade-participating countries and we saw no evidence that Croatia was lacking in this regard.
The commenters noted that we considered the disease risk posed by the small, family-operated breeding farm we visited (and backyard premises in general) to be different from that of vertically integrated commercial swine production systems, particularly with respect to animal disease traceability, animal sampling, and biosecurity. The commenters recommended that, before making a decision on Croatia's disease status, we require Croatia to provide a plan for risk reduction for small farms and backyard premises that addresses improving pre-harvest traceability, disease and biosecurity awareness, and disease sampling strategies that aid in early detection of trade-limiting foreign animal diseases.
In reply, we do consider the disease risk posed by small family-operated breeding farms and backyard premises to differ from the risk associated with Croatia's vertically integrated commercial swine production systems. However, we also observed measures that mitigate the risks associated with the small family-operated breeding farm we visited, including satisfactory operational, husbandry, and biosecurity standards. The farm controlled and catalogued on- and off-farm movements of animals, people, and supplies, and satisfied animal disease traceability requirements. Additionally, this farm was included in Croatia's swine disease surveillance program, as are other small farms in Croatia.
Regarding risk reduction plans, we note that Croatia does have such a plan in place for CSF in the form of legislation that places additional restrictions on swine, pork, and pork products produced in or moving from the counties of Vukovar-Srijem, Sisak-Moslavina, Karlovac, and Brod-Posavina, which are considered higher risk for CSF due to past serological events for CSF in feral swine. The family-operated breeding farm visited by APHIS was in Karlovac County and thus subject to these additional restrictions. As noted in the risk evaluation,
The additional risk reduction measures stipulate that fresh meat, meat preparations, or meat products consisting of or containing meat of swine originating from premises in Karlovac, Vukovar-Srijem, and Sisak-Moslavina Counties may be marketed and sold outside of these counties only if no evidence of CSF has been recorded in the previous 12 months on the premises and the premises is located outside a protection or surveillance zone. The swine are required to have resided for at least 90 days on the premises, and no swine are permitted to have been introduced into the premises within the previous 30 days before dispatch to slaughter. Under the additional risk reduction measures, Croatia also requires each premises to be
The commenters stated concern about the movement of swine within Croatia, noting that swine can be kept in livestock markets for no more than 12 hours and must be returned to the premises if not sold in that time. The commenters noted that commingling of swine outside of a production system or premises of origin at a market presents an elevated risk of disease transmission. For this reason, the commenters asked APHIS to clarify what, if any, regulations apply to reporting that animal movement back to the premises of origin and if there are any quarantine or movement restrictions or disease monitoring placed on that animal. The commenters recommended that APHIS ensure that reporting takes place for animal movement back to the premises of origin, that there are quarantine or movement restrictions as necessary, and that official monitoring for disease be in place and verified by Croatia.
We agree with the commenters that commingling of potentially infected but undetected swine in markets could contribute to rapid transmission and spread of contagious swine diseases. We acknowledged on page 46 of our risk evaluation that backyard premises with a single pig are exempt from most of Croatia's premises and animal registration requirements and that this presents a gap in animal disease traceability. We also acknowledged that backyard premises may present a biosecurity gap as some may not always conduct animal disease sampling or collect, analyze, and respond to changes in production data.
However, we consider it unlikely that animals/products from small farms or backyard premises will enter the export chain, as the movement and marketing patterns of Croatia's small farms and family premises are local and domestic in scope. Additionally, we concluded from our risk evaluation that the risk of disease transmission in small farm and backyard premises is mitigated at the premises and market levels. Although these premises are exempt from entry in the Croatian Agricultural Agency's Farm Register database, they must report the purchase of any pig to the competent veterinary organization at the time of delivery. Moreover, as the pig is most likely fed and fattened for personal consumption, we consider it unlikely that the pig would be moved off of a single- or double-swine backyard premises. Any swine that do move from a small premises require a movement permit and corresponding health certificate, and would most likely enter the local livestock market and be subject to the regulations enforced there. Livestock market regulations include the requirement that each animal consignment arriving to the market must be accompanied by a veterinary health certificate, issued within 30 days prior to movement, indicating veterinary inspection was performed prior to animals leaving the premises, as well as a travel document indicating that the transport vehicle underwent cleaning and disinfection.
Finally, the risk associated with an infected animal arriving at an animal market and being sent back to the premises of origin is also mitigated by veterinary inspection and corresponding documentation prior to animals moving to the market, as well as by the requirement that transport vehicles be disinfected.
Disease risk is further mitigated by other control measures that can be implemented in the event that a contagious animal disease is suspected or confirmed. The measures we observed included disinfection wheelbaths for vehicles and footbaths for people, and requiring that employees don personal protective clothing prior to entering the sale and transfer part of the market. Animal disease awareness educational pamphlets and contingency plans were on display in the market office, and the market has participated in disease outbreak simulation exercises.
Overall, we determined that Croatia has a sufficient infrastructure in place for reporting movement of pigs, including livestock markets, and concluded that disease monitoring took place at all critical points of Croatia's movement and marketing channels.
The commenters noted that Croatia conducts active surveillance for CSF, SVD, and FMD. However, they asked if we could determine whether active or passive surveillance is conducted for African swine fever (ASF), and whether the veterinary authority in Croatia rules out ASF in swine that present for inspection with case-compatible lesions.
We do not currently consider Croatia affected with ASF and did not conduct an evaluation of Croatia's ASF status. Thus, as the commenters acknowledged, passive and active surveillance for ASF are not specifically related to the risk assessment, which was conducted specifically for CSF, FMD, SVD, and rinderpest. However, we did conclude that Croatia maintains effective CSF and FMD emergency response plans, so if a disease investigation was triggered by case-compatible lesions we consider it highly likely that ASF would be appropriately confirmed or ruled out by Croatian veterinary officials.
We acknowledge that ASF has been a concern in the EU and in areas adjacent to the EU. The EU has laid down prevention and control measures
The commenters stated that the methods of investigation and testing in Croatia for suspected cases of CSF included in the risk evaluation appear to be inconsistent with the laboratory methods conducted in the United States that ensure rapid detection of CSF from samples submitted from a farm. The commenters suggested that this inconsistency could result in a significant delay in confirming the presence of CSF on farms in Croatia with case-compatible lesions and recommended that the competent veterinary authority of Croatia be required to improve laboratory detection methods so they are equivalent to those used in the United States.
Under OIE guidelines, APHIS import risk analyses are required to assess whether the end result of a sanitary measure or standard, in this case CSF detection methodology and disease confirmation, is equivalent to the end result of the importing country's measure or standard. While Croatia's CSF investigation and testing procedures may diverge slightly from U.S. protocols, we concluded from information gathered during the site visit that Croatia's CSF diagnostic
The commenters questioned our determination that contaminated food waste from Croatia poses a low disease risk to swine in the United States, noting that the risk findings we cited to help support this determination were conducted in 1995 and 2001 and do not reflect current risks to the U.S. pork industry.
One risk the commenters cited was the increased interstate trade of swine from States that allow the regulated feeding of garbage. The commenters recommended that the 1995 assessment be repeated using more recent data.
To the commenter's point, if contaminated meat products were imported from Croatia and managed to make it into plate waste, U.S. garbage feeding regulations will mitigate that risk. In 1995, we conducted a pathway analysis to estimate the likelihood of exposing domestic swine to infected waste. With 95 percent confidence, we estimated that 0.023 percent or less of plate and manufacturing waste would be inadequately processed prior to feeding to swine. Based on this percentage, less than 1 part in 4,300 of imported beef fed to swine as plate or manufacturing waste is likely to be inadequately cooked. The findings of a 2001 APHIS survey, which showed a substantial reduction in waste-feeding operations, further indicated that the risk of FMD exposure via feeding of contaminated waste to swine was continuing to decline.
Treatment of food waste to be fed to swine is covered under the Swine Health Protection Act
We acknowledge that waste feeding continues to be a potential pathway for transmission of swine diseases and that interstate trade patterns are subject to change. We maintain, however, that the 1995 and 2001 risk findings, combined with existing SHPA requirements, indicate to us a low likelihood of exposure of domestic swine to CSF, FMD, SVD, and rinderpest from food waste originating from Croatia.
The commenters noted that the SHPA requires licensed facilities to have quarterly or bi-yearly temperature checks of garbage-cooking equipment for a minimum of two and a maximum of four temperature checks each fiscal year. The commenters asked how many of the licensed garbage feeders actually were temperature checked twice in 2014 by a regulatory official. They indicated concerns with the records licensed facilities maintain to verify that they are meeting cooking time and temperature requirements on days they are not inspected, and recommended that we determine what records licensed facilities maintain in order to provide such verification to State and Federal animal health officials.
While we require that licensed U.S. garbage-feeding facilities observe all garbage heating requirements under the SHPA regulations, cooking temperature and treatment requirements are outside the scope of this risk evaluation. Regulations addressing these practices are contained in 9 CFR part 166 and include provisions for inspection of heating equipment and records. Garbage-feeding facilities suspected of violating the regulations for storing and heating garbage for feeding are subject to license suspension or revocation.
The commenters presented data from APHIS-VS reports to the U.S. Animal Health Association's Transmissible Diseases of Swine Committee indicating that, from 2009 to 2013, the number of non-licensed garbage feeders found by State and Federal animal health authorities in searches for non-licensed feeders was 104, 142, 68, 125, and 160, respectively. The commenters asked if APHIS has any supporting information on estimates of the number of unlicensed garbage-feeding facilities. Citing the disease risk posed by unlicensed garbage-feeding operations, the commenters expressed concern with our level of confidence that foreign animal diseases can be detected promptly in unlicensed garbage-feeding operations and asked if our emphasis on finding non-licensed feeders increased or decreased over the past couple of years. Procedures for the handling, processing, and feeding of food waste to swine in the United States are subject to our swine health protection regulations in 9 CFR part 166. Compliance with the regulations has improved in recent years, thereby reducing the probability of survival of FMD virus in the food waste. Searches for non-licensed garbage feeding facilities are regularly conducted using several different techniques as part of the duties of APHIS animal health staff, as well as State animal health and other State agency staff. During fiscal year 2014, animal health and other inspectors conducted 28,774 searches for non-licensed garbage feeding facilities with 122 documented non-licensed facilities identified, which indicates that unlicensed activity is infrequent.
When unlicensed garbage feeding facilities are identified, the unauthorized activity is documented, and the facility is brought into compliance. Depending on the State, all swine on such premises may be quarantined and tested for foreign animal diseases. Information on the number of inspections conducted to detect unlicensed garbage feeding facilities, the number of unlicensed facilities identified, and resolution of cases resulting from such identification are captured at the State level and evaluated by APHIS on a regular basis. Given the regular monitoring of these facilities and their relatively small number, we stand by the conclusions we reached in our 1995 risk analysis cited above.
The commenters stated a concern that budget cuts to APHIS-VS and State animal health officials have negatively affected the ability to effectively carry out the regulatory activities supporting the SHPA. They also expressed concern that the reduction in such activities has reduced the number of inspection and searches for unlicensed garbage-feeding operations to a level that is lower than what was indicated in the 1995 risk analysis.
Budget cuts to APHIS have necessitated a reordering of priorities in relation to SHPA-related activities. We have deemphasized or passed on to State partners or other cooperators lower-yield activities, such as visiting
The commenters noted that the environmental assessment (EA) provided with this rulemaking was the May 2011 EA for the importation of swine and swine commodities from Slovakia. They also noted that APHIS provided a supporting document that was an amended finding of no significant impact (FONSI) from importation of swine and swine commodities from Croatia that uses the EA from Slovakia as the basis for the amended finding related to Croatia. The commenters requested that APHIS expand on how it is justifiable to use an EA prepared for other countries and apply it to Croatia.
APHIS has conducted animal health status evaluations for multiple EU Member States for swine diseases. Since 2006 we have recognized the CSF, FMD, SVD, and/or rinderpest status for EU Member States Latvia, Lithuania, Poland, the Czech Republic, Slovakia, Slovenia, Estonia, and Hungary, and for certain countries that have entered into agricultural equivalence agreements with the EU. In each case, we determined that measures are in place to mitigate the risk of CSF, SVD, FMD, and/or rinderpest introduction into the United States through importation of swine, swine commodities, ruminants, and ruminant commodities from countries or regions that we recognize as low risk for CSF and free of SVD, FMD, and rinderpest.
Given that the EU applies and ensures enforcement of the same disease mitigation requirements across all EU Member States, we recognized that the single-state evaluations we were conducting were redundant and thus unnecessary with respect to meeting the requirements of the National Environmental Protection Act (NEPA). After we consulted with Agency specialists on NEPA, we did an environmental impact analysis comparison of the 2011 Slovakia EA analysis in regards to the proposed action of this notice for the EU Member State Croatia and determined that the environmental analyses of the Slovakia EA were similar and sufficient to cover the proposed action for Croatia. The 2011 Slovakia EA stated that for any like/similar future regionalization actions proposed for EU Member States, APHIS would incorporate the Slovakia EA by reference in a new FONSI issued for a proposed new action for an EU Member State. That is what we have done for this proposed action for Croatia.
Additionally, we determined that future proposed actions of this nature pose negligible environmental impacts to each EU Member State or country that has entered into an agricultural equivalency agreement with the EU, provided that a disease assessment finds them to be free of or a low risk for relevant diseases. As Croatia is an EU Member State and because we have determined that Croatia is free of SVD, FMD, and rinderpest, and at low risk for CSF, we believe that the “like/similar action” environmental analyses approach as presented in the 2011 Slovakia EA/FONSI is appropriate to use for the proposed action for Croatia.
Based on the evaluation and the reasons given in this document in response to comments, we are recognizing Croatia as free of FMD, rinderpest, and SVD, and low risk for CSF. The lists of regions recognized as free or at low risk of these diseases can be found by visiting the APHIS Web site at
7 U.S.C. 450, 7701-7772, 7781-7786, and 8301-8317; 21 U.S.C. 136 and 136a; 31 U.S.C. 9701; 7 CFR 2.22, 2.80, and 371.4.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (“the Department”) preliminarily determines that uncovered innerspring units (“innersprings units”) completed or assembled in Malaysia by Goldon Bedding Manufacturing Sdn. Bhd. (“Goldon”) using components from the People's Republic of China (“PRC”), and exported to the United States, are circumventing the antidumping duty order on innersprings from the PRC, as provided in section 781(b) of the Tariff Act of 1930, as amended (“the Act”).
Susan Pulongbarit, AD/CVD Operations, Office V, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-4031.
On December 31, 2014, the Department initiated an anticircumvention inquiry on imports of innersprings from the PRC exported by Goldon.
Because Goldon failed to respond to the questionnaire, the record does not contain complete information regarding the factors set forth in section 781(b) of the Tariff Act of 1930 (the “Act”). Accordingly, we have based our determination on facts otherwise available, pursuant to sections 776(a)(2)(A) and (C) of the Act, applying an adverse inference, pursuant to section 776(b) of the Act.
The merchandise subject to the order is uncovered innerspring units. The product is currently classified under subheading 9404.29.9010 and has also been classified under subheadings 9404.10.0000, 7326.20.0070, 7320.20.5010, 7320.90.5010, or 7326.20.0071 of the Harmonized Tariff Schedule of the United States (“HTSUS”). The HTSUS subheadings are provided for convenience and customs purposes only; the written product description of the scope of the order is dispositive.
The products covered by this inquiry are innerspring units, as described above, that are manufactured in Malaysia by Goldon with PRC-origin components and other direct materials, such as helical wires, and that are subsequently exported from Malaysia to the United States.
The Department has conducted this preliminary determination of circumvention in accordance with section 781(b) of the Act and 19 CFR 351.225(h). For a full description of the methodology underlying our conclusions,
As detailed in the Preliminary Decision Memorandum, the Department preliminarily determines, based on facts available with an adverse inference pursuant to sections 776(a) and (b) of the Act, that innerspring units completed and assembled in Malaysia by Goldon using components from the PRC and exported from Malaysia to the United States are circumventing the
In accordance with 19 CFR 351.225(l)(2), the Department will direct CBP to suspend liquidation and to require a cash deposit of estimated duties at the rate applicable to the exporter, on all unliquidated entries of innerspring units produced by Goldon that were entered, or withdrawn from warehouse, for consumption on or after December 22, 2014, the date of initiation of the anticircumvention inquiry.
Should the Department conduct an administrative review in the future, and determine in the context of that review that Goldon did not produce for export innerspring units using PRC-origin innerspring components, the Department will consider initiating a changed circumstances review pursuant to section 751(b) of the Act to determine if the continued suspension of all innerspring units produced by Goldon is warranted.
The Department, consistent with section 781(e)(1)(B) of the Act and 19 CFR 351.225(f)(7)(i)(B), has notified the International Trade Commission (“ITC”) of this preliminary determination to include the merchandise subject to this anticircumvention inquiry within the
Interested parties may submit case briefs within 15 days after the date of publication of these preliminary results of review in the
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, filed electronically using ACCESS. An electronically filed document must be received successfully in its entirety by the Department's electronic records system, ACCESS, by 5:00 p.m. Eastern Time, within 30 days after the date of publication of this notice.
Pursuant to section 781(f) of the Act, the final determination with respect to this anticircumvention inquiry, including the results of the Department's analysis of any written comments, will be issued no later than December 2, 2015, unless extended.
This preliminary affirmative circumvention determination is published in accordance with section 781(b) of the Act and 19 CFR 351.225.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; public meeting.
The New England Fishery Management Council (Council) is scheduling a public meeting of its Ecosystem Based Fishery Management Committee to consider actions affecting New England fisheries in the exclusive economic zone (EEZ). Recommendations from this group will be brought to the full Council for formal consideration and action, if appropriate.
This meeting will be held on Tuesday, November 10, 2015 at 9 a.m.
The meeting will be held at the Fairfield Inn & Suites, 185 MacArthur Drive, New Bedford, MA 02740; telephone: (774) 634-2000; fax: (774) 634-2001.
Thomas A. Nies, Executive Director, New England Fishery Management Council; telephone: (978) 465-0492.
The committee will receive a progress report and provide guidance to the Plan Development Team on the development of an example Fishery Ecosystem Plan (FEP). This meeting will focus on the FEP components, strawman goals and objectives and a summary of how various ecosystem models address FEP data needs. The Committee will also formulate comments on NOAA Fisheries Draft Ecosystem-Based Fisheries Management Policy
This meeting is physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Thomas A. Nies, Executive Director, at (978) 465-0492, at least 5 days prior to the meeting date.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; public meeting.
The Mid-Atlantic Fishery Management Council's (MAFMC's) Summer Flounder, Scup, and Black Sea Bass Advisory Panel will hold a public meeting jointly with the Atlantic States Marine Fisheries Commission's (ASMFC's) Summer Flounder, Scup, and Black Sea Bass Advisory Panel.
The meeting will be held on Tuesday November 17, 2015, from 4 p.m. to 7 p.m. See
The meeting will take place over webinar with a telephone-only connection option. Details on how to connect to the webinar by computer and by telephone will be available at:
Christopher M. Moore, Ph.D., Executive Director, Mid-Atlantic Fishery Management Council, telephone: (302) 526-5255.
The Mid-Atlantic Fishery Management Council's Summer Flounder, Scup, and Black Sea Bass Advisory Panel, together with the Atlantic States Marine Fisheries Commission's Advisory Panel, will meet on Tuesday November 17, 2015 (see
A detailed agenda and background documents will be made available on the Council's Web site (
The 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.
The Department of Commerce will submit to the Office of Management and Budget (OMB) for clearance the following proposal for collection of information under the provisions of the Paperwork Reduction Act (44 U.S.C. Chapter 35).
NOAA is mentoring student interns from the Monterey Institute for International Studies to estimate the market and non-market economic values associated with non-consumptive recreation uses (
We will conduct surveys of the for hire operations that take people out for non-consumptive recreation, to obtain total use by type of activity and the spatial use by type of activity. Information will also be obtained on costs-and-earnings of the operations, knowledge, attitudes and perceptions of sanctuary management strategies and regulations, and demographic information on owner/captains and crews. Surveys will also be conducted of the passengers aboard the for hire operation boats to obtain their market and non-market economic use values for non-consumptive recreation use and how those value change with changes in natural resource attribute conditions and user characteristics. Additional information will be obtained on importance-satisfaction ratings of key natural resource attributes, facilities and services, knowledge, attitudes and perceptions of management strategies and regulations, and demographic profiles of passengers.
This information collection request may be viewed at reginfo.gov. Follow the instructions to view Department of Commerce collections currently under review by OMB.
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of public hearings.
The South Atlantic Fishery Management Council (SAFMC) will hold a series of public hearings pertaining to Regulatory Amendment 25 to the Snapper Grouper Fishery Management Plan (FMP) for the South Atlantic and Regulatory Amendment 1 to the Dolphin Wahoo Fishery Management Plan for the Atlantic. Regulatory Amendment 25 to the Snapper Grouper FMP addresses management measures for blueline tilefish, yellowtail snapper and black sea bass. Regulatory Amendment 1 to the Dolphin Wahoo FMP addresses a commercial trip limit for the dolphin fishery in the Atlantic.
The public hearings will be held via webinar with listening/comment stations from November 9-12, 2015. A webinar with listening/comment stations will be held November 9, 2015 for Regulatory Amendment 25. A webinar with listening/comment stations will be held November 12, 2015 for both Snapper Grouper Regulatory Amendment 25 and Dolphin Wahoo Regulatory Amendment 1.
The public hearings will be conducted via webinar and accessible via the internet from the Council's Web site at
1. November 9, 2015—Local Listening/Comment Stations: Georgia Department of Natural Resources, Coastal Resources Division, One Conservation Way, Brunswick, GA 31520-8687; phone: (912) 264-7218 and Hilton Garden Inn Charleston Airport, 5265 International Boulevard, North Charleston, SC 29418; phone: (843) 308-9330.
2. November 12, 2015—Local Listening/Comment Station: Dare County Government Complex, Room 168, 1st Floor, 954 Marshall C. Collins Drive, Manteo, NC 27954; phone: (252) 475-5000; and Wingate by Wyndham (Hotel), 2465 State Route 16, St. Augustine, FL 32092; phone: (904) 824-9229.
1. November 12, 2015—Local Listening/Comment Station: Dare County Government Complex, Room 168, 1st Floor, 954 Marshall C. Collins Drive, Manteo, NC 27954; phone: (252) 475-5000; and Wingate by Wyndham (Hotel), 2465 State Route 16, St. Augustine, FL 32092; phone: (904) 824-9229.
Kim Iverson, Public Information Officer, SAFMC; phone: (843) 571-4366 or toll free: (866) SAFMC-10; fax: (843) 769-4520; email:
This amendment includes alternatives to:
(1) For blueline tilefish, specify the Acceptable Biological Catch (ABC) for the South Atlantic, adjust Annual Catch Limit (ACL), Optimum Yield (OY) and other management parameters as necessary based on the new ABC; revise the commercial trip limit; and modify the recreational bag limit;
(2) Modify the recreational and commercial fishing year and commercial Accountability Measures for yellowtail snapper; and
(3) Increase the recreational bag limit for black sea bass.
This amendment includes management alternatives to:
(1) Establish a commercial trip limit for dolphin.
Written comments may be directed to Bob Mahood, Executive Director, SAFMC (see Council address) or via email to
During the webinars, Council staff will present an overview of the amendment and will be available for informal discussions and to answer questions via webinar. Members of the public will have an opportunity to go on record to record their comments for consideration by the Council. Area Council representatives will be present at the local comment stations.
These hearings are physically accessible to people with disabilities. Requests for auxiliary aids should be directed to the Council office (see
The times and sequence specified in this agenda are subject to change.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of online webinar.
The Pacific Fishery Management Council's (Pacific Council's) Scientific and Statistical Committee (SSC) will hold an online webinar to review a revised west coast limited entry trawl individual fishing quota (IFQ) projection model developed by the Pacific Council's Groundfish Management Team (GMT). The online SSC webinar is open to the public.
The SSC webinar will commence at noon PST, Monday, November 9, 2015 and continue until 2 p.m. or as necessary to complete business for the day.
To attend the SSC webinar, please join online at
Mr. John DeVore, Pacific Council; telephone: (503) 820-2413.
The specific objectives of the SSC webinar are to review revisions to the GMT's west coast limited entry trawl IFQ projection model to ensure the changes recommended by the SSC's Groundfish and Economics Subcommittees in June were implemented and the model behaves as expected. During the webinar, the SSC will consider endorsing the GMT's IFQ model to inform management decisions. No management actions will be decided in this webinar. Public comments during the webinar will be received from attendees at the discretion of the SSC chair.
Although non-emergency issues not identified in the webinar agenda may come before the webinar participants for discussion, those issues may not be the subject of formal action during this webinar. Formal action at the webinar will be restricted to those issues specifically listed 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 webinar participants' intent to take final action to address the emergency.
The public listening station at the Pacific Council office is physically accessible to people with disabilities. Requests for auxiliary aids should be directed to Mr. Kris Kleinschmidt at (503) 820-2280 at least 5 days prior to the webinar date.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; request for comments.
The Assistant Regional Administrator for Sustainable Fisheries, Greater Atlantic Region, NMFS, has made a preliminary determination that an Exempted Fishing Permit application contains all of the required information and warrants further consideration. This Exempted Fishing Permit would allow commercial fishing vessels to fish outside of the limited access sea scallop regulations in support of study investigating coastal spawning of winter flounder in Southern New England.
Regulations under the Magnuson-Stevens Fishery Conservation and Management Act require publication of this notification to provide interested parties the opportunity to comment on applications for proposed Exempted Fishing Permits.
Comments must be received on or before November 9, 2015.
You may submit written comments by any of the following methods:
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Shannah Jaburek, Fisheries Management Specialist, 978-282-8456.
NOAA has awarded the Coonamesset Farm Foundation (CFF) a grant through the 2015 Saltonstall-Kennedy grant program, in support of a project titled “Investigating Offshore Essential Fish Habitat of Southern New England Winter Flounder.” To conduct this research, CFF submitted a complete application for an EFP on August 4, 2015. The applicant proposes to investigate questions associated with spawning winter flounder in Southern New England (SNE) by conducting multiple research activities, which include:
1. A paired scallop dredge survey to identify and monitor the distribution of winter flounder;
2. Test dredge gear twine top configurations and apron lengths to reduce finfish bycatch;
3. Attempt to observe winter flounder spawning behavior using a remotely operated vehicle (ROV);
4. Conduct a benthic habitat video survey; and
5. Sample for a winter flounder eggs using a plankton net.
CFF is requesting exemptions that would allow commercial fishing vessels be exempt from the Atlantic sea scallop days-at-sea (DAS) allocations at 50 CFR 648.53(b); crew size restrictions at § 648.51(c); Atlantic sea scallop observer program requirements at § 648.11(g); and possession limits and minimum size requirements specified in 50 CFR part 648, subsections B and D through O, for sampling purposes only. Any fishing activity conducted outside the scope of the exempted fishing activity would be prohibited.
Five vessels would conduct the dredge survey and gear testing on six 5-day trips, for 30 total DAS. Each trip would complete approximately 60 dredge tows per trip for an overall total of 360 tows for the project. The project would also conduct a single video survey trip utilizing a benthic sled. Trips would take place in the open areas of SNE in December 2015-May 2016.
All dredge tows would use two 15-foot (4.57-m) Turtle Deflector Dredges (TDD) and be conducted in tandem for a duration of 30 minutes at a tow speed of approximately 4.8 knots. One dredge would be rigged with a 7-row apron and 60-mesh wide twine top while the other dredge would be rigged with a 5-row apron and 45-mesh wide twine top. To examine factors that may influence flatfish bycatch rates such as habitat characteristics and fish behavior in response to the TDD, each dredge would have an underwater camera attached to the bale bar. When researchers identify large numbers of spawning winter flounder during the dredge survey, they would deploy the ROV to film spawning behavior interactions.
For all tows, researchers would count and weigh sea scallop catch. Researchers would measure scallops from one randomly selected basket from each dredge in 5-mm increments to determine size selectivity. Researchers would sort finfish catch by species then count, weigh, and measure finfish catch in 1-mm increments. Researchers would also weigh, sex, and assess the reproductive stage of all winter flounder greater than 32 cm. The vessels would not retain catch for longer than needed to conduct sampling and vessels would not land any catch for sale. CFF researchers would accompany all trips, and be in charge of sampling activities.
The project would also use a commercial vessel for a single dedicated video trip utilizing a benthic underwater survey sled. At each of the survey stations the benthic sled would be deployed and towed for 5-10 minutes at a speed of 1.5-2 knots. Researchers would attach a live feed video camera transmitting video back to the vessel, and two underwater cameras taking high definition still shots to the benthic sled. There would also be two low level lights attached to the benthic sled in order to illuminate the area for the cameras. The video footage and photos from the benthic sled survey would be compared to still shots take during the dredge surveys. Researchers would also attach a plankton net to the benthic sled. The plankton net would be 101.60 cm long with a 27.94 x 45.72-cm opening, and a mesh size of 0.05 cm. The plankton net would allow researchers to see if there are winter flounder eggs present at each of the survey stations.
CFF has requested these exemptions to allow them to conduct experimental dredge towing without being charged DAS. Participating vessels need crew size waivers to accommodate science personnel and possession waivers will enable them to conduct finfish sampling activities. NMFS would waive observer notification requirements because the research activity is not representative of a commercial scallop fishing trip.
If approved, the applicant may request minor modifications and extensions to the EFP throughout the year. EFP modifications and extensions may be granted without further notice if they are deemed essential to facilitate completion of the proposed research and have minimal impacts that do not change the scope or impact of the initially approved EFP request. Any fishing activity conducted outside the scope of the exempted fishing activity would be prohibited.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notification of a proposal to conduct exempted fishing; reopening of comment period.
This action reopens the comment period for an application for an exempted fishing permit for horseshoe crab that published on October 7, 2015. The original comment period closed 13 days later on October 19, 2015, which is two days shorter than the 15-day minimum comment time period required in our regulations. We are therefore reopening the comment period through October 27, 2015, to make-up for this shortfall and to provide additional opportunity for public comment.
Written comments must be received on or before October 27, 2015.
Written comments should be sent to Alan Risenhoover, Director, Office of Sustainable Fisheries, NMFS, 1315 East-West Highway, Room 13362, Silver Spring, MD 20910. Mark the outside of the envelope “Comments on Horseshoe Crab EFP Proposal.”
Comments may also be sent via fax to (301) 713-0596. Comments on this notice may also be submitted by email to:
Derek Orner, Office of Sustainable Fisheries, (301) 427-8567.
A notification of a proposal to conduct exempted fishing was published on October 7, 2015 (80 FR 60633) that would allow the harvest of up to 10,000 horseshoe crabs from the Carl N. Schuster Jr. Horseshoe Crab Reserve for biomedical purposes and require, as a condition of the exempted fishing permit (EFP), the collection of data related to the status of horseshoe crabs within the reserve. The Director, Office of Sustainable Fisheries, has made a preliminary determination that the subject EFP application submitted by Limuli Laboratories of Cape May Court House, NJ, contains all the required information and warrants further consideration.
The notification of EFP application published in the
16 U.S.C. 1801
Bureau of Consumer Financial Protection.
Notice and request for comment.
In accordance with the Paperwork Reduction Act of 1995 (PRA), the Consumer Financial Protection Bureau (Bureau) is proposing to renew the Office of Management and Budget (OMB) approval for an existing information collection titled, “Generic Information Collection Plan for the Collection of Qualitative Feedback on Bureau Service Delivery.”
Written comments are encouraged and must be received on or before November 23, 2015 to be assured of consideration.
You may submit comments, identified by the title of the information collection, OMB Control Number (see below), and docket number (see above), by any of the following methods:
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Documentation prepared in support of this information collection request is available at
This submission is requesting OMB to renewal for additional three (3) years its approval of this generic information collection plan.
Bureau of Consumer Financial Protection.
Notice and request for comment.
In accordance with the Paperwork Reduction Act of 1995 (PRA), the Consumer Financial Protection Bureau (Bureau) is proposing a new information collection for Office of Management and Budget (OMB) approval titled, “Owning a Home Evaluation Study.”
Written comments are encouraged and must be received on or before November 23, 2015 to be assured of consideration.
You may submit comments, identified by the title of the information collection, OMB Control Number (see below), and docket number (see above), by any of the following methods:
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•
Documentation prepared in support of this information collection request is available at
Corporation for National and Community Service.
Notice.
The Corporation for National and Community Service (CNCS), as part of its continuing effort to reduce paperwork and respondent burden, conducts a pre-clearance consultation program to provide the general public and federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)(A)). This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, and the impact of the requirement on respondents can be properly assessed.
Currently, CNCS is soliciting comments concerning its recordkeeping requirement in 45 CFR 2540.205 and 2540.206. CNCS grantees and subgrantees must maintain records to document completion of required National Service Criminal History Checks. This is not a notice of proposed rulemaking.
Written comments must be submitted to the individual and office listed in the
You may submit comments, identified by the title of the information collection activity, by any of the following methods:
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(3)
(4)
Individuals who use a telecommunications device for the deaf (TTY-TDD) may call 1-800-833-3722 between 8:00 a.m. and 8:00 p.m. Eastern Time, Monday through Friday.
Aaron Olszewski, 202-606-6670, or by email at
This is not a notice of proposed rulemaking. CNCS is particularly interested in comments that:
• Evaluate whether the proposed collection of information is necessary for the efficient performance of the functions of CNCS, 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 expected to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology (
Section 189D of the National and Community Service Act of 1990, as amended, requires CNCS grantees and subgrantees to conduct a National Service Criminal History Check on individuals in covered positions. Documenting compliance with the requirement is critical to that responsibility.
CNCS requests renewal of the previous approval.
The requirements will be used in the same manner as the existing application. CNCS also seeks to continue using the current application until the revised application is approved by OMB. The current application is due to expire on February 29, 2016.
Comments submitted in response to this notice will be summarized and/or included in the request for Office of Management and Budget approval; they will also become a matter of public record.
Department of Defense.
Notice of meeting.
The Department of Defense is publishing this notice to announce the following Federal Advisory Committee meeting of the Judicial Proceedings since Fiscal Year 2012 Amendments Panel (“the Judicial Proceedings Panel” or “the Panel”). The meeting is open to the public.
A meeting of the Judicial Proceedings Panel will be held on Friday, November 6, 2015. The Public Session will begin at 9:00 a.m. and end at 4:45 p.m.
The Holiday Inn Arlington at Ballston, 4610 N. Fairfax Drive, Arlington, Virginia 22203.
Ms. Julie Carson, Judicial Proceedings Panel, One Liberty Center, 875 N. Randolph Street, Suite 150, Arlington, VA 22203. Email:
Due to circumstances beyond the control of the Designated Federal Officer and the Department of Defense, the Judicial Proceedings since Fiscal Year 2012 Amendments Panel (“the Judicial Proceedings Panel was unable to provide public notification of its meeting of November 6, 2015, as required by 41 CFR 102-3.150(a). Accordingly, the Advisory Committee Management Officer for the Department of Defense, pursuant to 41 CFR 102-3.150(b), waives the 15-calendar day notification requirement.
This public meeting is being held under the provisions of the Federal Advisory Committee Act of 1972 (5 U.S.C., Appendix, as amended), the Government in the Sunshine Act of 1976 (5 U.S.C. 552b, as amended), and 41 CFR 102-3.150.
Office of the Secretary of Defense, DoD.
Notice to alter an existing System of Records.
The Office of the Secretary of Defense proposes to alter an existing system of records, DPR 32, entitled “Employer Support of the Guard and Reserve Ombudsman and Outreach Programs” to record information related to the mediation of disputes and answering of inquiries related to the USERRA; by tracking case assignments and mediation results of potential conflicts between employers and the National Guard, Reserves, or NDMS members they employ; and by reporting statistics related to the Ombudsman Program in aggregate and at the state committee-level. These records are also used as a management tool for statistical analysis, tracking, reporting, evaluating program effectiveness and conducting research.
Comments will be accepted on or before November 23, 2015. This proposed action will be effective the day following the end of the comment period unless comments are received which result in a contrary determination.
You may submit comments, identified by docket number and title, by any of the following methods:
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Ms. Cindy Allard, Chief, OSD/JS Privacy Office, Freedom of Information Directorate, Washington Headquarters Service, 1155 Defense Pentagon, Washington, DC 20301-1155, or by phone at (571)372-0461.
The Office of the Secretary of Defense notices for systems of records subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended, have been published in the
Employer Support of the Guard and Reserve Ombudsman and Outreach
Delete entry and replace with “DHRA 16.”
Delete entry and replace with “Inquiry and Case Management System (ICMS).”
Delete entry and replace with “Defense Information Systems Agency (DISA), Computing Directorate Mechanicsburg, 5450 Carlisle Pike, Mechanicsburg, PA 17050-2411.
Backup: Iron Mountain, 1665 S 5350 W., Salt Lake City, UT 84104-4721.”
Delete entry and replace with “Members of the National Guard, Reserves, and National Disaster Medical System (NDMS) who submit inquiries or request mediation; Employer Support of the Guard and Reserve (ESGR) employees; civilian employers; contractors and volunteers who handle inquiries and cases; and those who submit inquiries.”
Delete entry and replace with “Individual's full name, home address, phone number, email address; current Uniformed Service and Service member pay grade; ESGR case number; type of Uniformed Services Employment and Reemployment Rights Act (USERRA) issue; employer name, employer type, employer's contact name, contact phone, email and address; name, email and state committee/ESGR affiliation of ESGR employee, contractor, or volunteer that handles an inquiry or mediation case; and case notes.”
Delete entry and replace with “38 U.S.C. 43, Employment and Reemployment Rights of Members of the Uniformed Services; 5 U.S.C. 574, Confidentiality; 5 U.S.C. Part I, Chapter 5, Subchapter IV, Alternative Means of Dispute Resolution in the Administrative Process; 42 U.S.C. 300hh-11, National Disaster Medical System, ((d)(3) Employment and reemployment rights); 20 CFR 1002, Regulations Under the Uniformed Services Employment and Reemployment Rights Act of 1994; 5 CFR 353, Restoration to Duty from Uniformed Service or Compensable Injury; DoD Directive 1250.01, National Committee for Employer Support of the Guard and Reserve (NCESGR); DoD Instruction 1205.22, Employer Support of the Guard and Reserve; and DoD Instruction 1205.12, Civilian Employment and Reemployment Rights of Applicants for, and Service Members and Former Service Members of the Uniformed Services.”
Delete entry and replace with “To record information related to the mediation of disputes and answering of inquiries related to the USERRA; by tracking case assignments and mediation results of potential conflicts between employers and the National Guard, Reserves, or NDMS members they employ; and by reporting statistics related to the Ombudsman Program in aggregate and at the state committee-level. These records are also used as a management tool for statistical analysis, tracking, reporting, evaluating program effectiveness and conducting research.”
Delete entry and replace with “In addition to those disclosures generally permitted under 5 U.S.C. 552a(b) of the Privacy Act of 1974, as amended, the records contained herein may be disclosed outside the DoD as a routine use pursuant to 5 U.S.C. 552a(b)(3) as follows:
To Department of Labor for Congressionally-mandated USERRA reporting (38 U.S.C. Employment and Reemployment Rights of Members of the Uniformed Services § 4432, Reports).
Law Enforcement Routine Use: If a system of records maintained by a DoD Component to carry out its functions indicates a violation or potential violation of law, whether civil, criminal, or regulatory in nature, and whether arising by general statute or by regulation, rule, or order issued pursuant thereto, the relevant records in the system of records may be referred, as a routine use, to the agency concerned, whether federal, state, local, or foreign, charged with the responsibility of investigating or prosecuting such violation or charged with enforcing or implementing the statute, rule, regulation, or order issued pursuant thereto.
Disclosure When Requesting Information Routine Use: A record from a system of records maintained by a DoD Component may be disclosed as a routine use to a federal, state, or local agency maintaining civil, criminal, or other relevant enforcement information or other pertinent information, such as current licenses, if necessary to obtain information relevant to a DoD Component decision concerning the hiring or retention of an employee, the issuance of a security clearance, the letting of a contract, or the issuance of a license, grant, or other benefit.
Disclosure of Requested Information Routine Use: A record from a system of records maintained by a DoD Component may be disclosed to a federal agency, in response to its request, in connection with the hiring or retention of an employee, the issuance of a security clearance, the reporting of an investigation of an employee, the letting of a contract, or the issuance of a license, grant, or other benefit by the requesting agency, to the extent that the information is relevant and necessary to the requesting agency's decision on the matter.
Congressional Inquiries Disclosure Routine Use: Disclosure from a system of records maintained by a DoD Component may be made to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of that individual.
Disclosure to the Office of Personnel Management Routine Use: A record from a system of records subject to the Privacy Act and maintained by a DoD Component may be disclosed to the Office of Personnel Management (OPM) concerning information on pay and leave, benefits, retirement deduction, and any other information necessary for the OPM to carry out its legally authorized government-wide personnel management functions and studies.
Disclosure to the Department of Justice for Litigation Routine Use: A record from a system of records maintained by a DoD Component may be disclosed as a routine use to any component of the Department of Justice for the purpose of representing the Department of Defense, or any officer, employee or member of the Department in pending or potential litigation to which the record is pertinent.
Disclosure of Information to the National Archives and Records Administration Routine Use: A record from a system of records maintained by a DoD Component may be disclosed as a routine use to the National Archives and Records Administration for the purpose of records management inspections conducted under authority of 44 U.S.C. 2904 and 2906.
Disclosure to the Merit Systems Protection Board Routine Use: A record from a system of records maintained by a DoD Component may be disclosed as a routine use to the Merit Systems Protection Board, including the Office of the Special Counsel for the purpose of
Data Breach Remediation Purposes Routine Use: A record from a system of records maintained by a Component may be disclosed to appropriate agencies, entities, and persons when (1) The Component suspects or has confirmed that the security or confidentiality of the information in the system of records has been compromised; (2) the Component has determined that as a result of the suspected or confirmed compromise there is a risk of harm to economic or property interests, identity theft or fraud, or harm to the security or integrity of this system or other systems or programs (whether maintained by the Component or another agency or entity) that rely upon the compromised information; and (3) the disclosure made to such agencies, entities, and persons is reasonably necessary to assist in connection with the Components efforts to respond to the suspected or confirmed compromise and prevent, minimize, or remedy such harm.
The DoD Blanket Routine Uses set forth at the beginning of the Office of the Secretary of Defense (OSD) compilation of systems of records notices may apply to this system. The complete list of DoD Blanket Routine Uses can be found online at:
Delete entry and replace with “Electronic storage media.”
Delete entry and replace with “Individual's full name and ESGR case number.”
Delete entry and replace with “Physical controls include combination locks, cipher locks, key cards, identification badges, closed circuit televisions, and controlled screenings. Technical controls include user identification and password, intrusion detection system, encryption, Common Access Card, firewall, virtual private network, role-based access controls, and two-factor authentication. Administrative controls include periodic security audits, regular monitoring of users' security practices, methods to ensure only authorized personnel access information, encryption of backups containing sensitive data, backups secured off-site, and use of visitor registers.”
Delete entry and replace with “Temporary. Contact information (email, phone number, details/notes of questions asked) from the inquiry data destroy 90 days after inquiry has been closed.
Masterfile: Destroy 3 years after settlement is implemented or case is discontinued.”
Delete entry and replace with “Executive Director, Headquarters, Employer Support of the Guard and Reserve, 4800 Mark Center Drive, Alexandria, VA 22350-1200.”
Delete entry and replace with “Individuals seeking to determine if information about themselves is contained in this system of records should address written inquiries to the Executive Director, Headquarters, Employer Support of the Guard and Reserve, 4800 Mark Center Drive, Alexandria, VA 22350-1200.
Signed, written requests should contain the individual's full name and personal contact information (address, phone number, and email).”
Delete entry and replace with “Individuals seeking access to records about themselves contained in this system should address written inquiries to the Office of the Secretary of Defense/Joint Staff, Freedom of Information Act Requester Service Center, Office of Freedom of Information, 1155 Defense Pentagon, Washington, DC 20301-1155.
Signed, written requests should include the individual's full name and personal contact information (address, phone number, email) and the name and number of this system of records notice.”
Delete entry and replace with “Individual, and Member Management System (MMS).”
Department of Defense (DoD).
Notice of Federal Advisory Committee meeting.
The Department of Defense is publishing this notice to announce that the following Federal Advisory Committee meeting of the Defense Health Board will take place.
Davis Conference Center, 7633 Bayshore Boulevard, MacDill Air Force Base, Florida 33621 (Pre-meeting screening and registration required; see guidance in
The Executive Director of the Defense Health Board is Ms. Christine Bader, 7700 Arlington Boulevard, Suite 5101, Falls Church, Virginia 22042, (703) 681-6653, Fax: (703) 681-9539,
This meeting is being held under the provisions of the Federal Advisory Committee Act of 1972 (5 U.S.C., Appendix, as amended), the Government in the Sunshine Act of 1976 (5 U.S.C. 552b, as amended), and 41 CFR 102-3.150, and in accordance with section 10(a)(2) of the Federal Advisory Committee Act.
Additional information, including the agenda and electronic registration, is available at the DHB Web site,
The purpose of the meeting is to conduct a decision briefing for deliberation and provide progress updates on specific taskings before the DHB. In addition, the DHB will receive information briefings on current issues or lessons learned related to military medicine, health policy, health
Pursuant to 5 U.S.C. 552b, as amended, and 41 CFR 102-3.140 through 102-3.165 and subject to availability of space, the DHB meeting is open to the public from 9:30 a.m. to 11:30 a.m. and 12:30 p.m. to 5:00 p.m. on November 9, 2015. The DHB anticipates deliberating a decision briefing from the Neurological/Behavioral Health Subcommittee regarding Population Normative Values for Post-Concussive Computerized Neurocognitive Assessments. In addition, information briefings will be presented on mental health treatment collaboration with the James A. Haley Veterans' Hospital, Sustained Medical and Readiness Training (SMART), medical evaluation boards, an update on the work of the Joint Committee to Create a National Policy to Enhance Survivability from Intentional Mass-Casualty and Active Shooter Events, and medical implications of anti-access/area denial.
Pursuant to 5 U.S.C. 552b, as amended, and 41 CFR 102-3.140 through 102-3.165 and subject to availability of space, this meeting is open to the public. Seating is limited and is on a first-come basis. All members of the public who wish to attend the public meeting must contact Ms. Kendal Brown at the number listed in the section
Individuals requiring special accommodations to access the public meeting should contact Ms. Kendal Brown at least five (5) business days prior to the meeting so that appropriate arrangements can be made.
Any member of the public wishing to provide comments to the DHB may do so in accordance with 41 CFR 102-3.105(j) and 102-3.140 and section 10(a)(3) of the Federal Advisory Committee Act, and the procedures described in this notice.
Individuals desiring to provide comments to the DHB may do so by submitting a written statement to the DHB Designated Federal Officer (DFO) (see
If the written statement is not received at least five (5) business days prior to the meeting, the DFO may choose to postpone consideration of the statement until the next open meeting.
The DFO will review all timely submissions with the DHB President and ensure they are provided to members of the DHB before the meeting that is subject to this notice. After reviewing the written comments, the President and the DFO may choose to invite the submitter to orally present their issue during an open portion of this meeting or at a future meeting. The DFO, in consultation with the DHB President, may allot time for members of the public to present their issues for review and discussion by the Defense Health Board.
Department of the Army, U.S. Army Corps of Engineers, DoD.
Notice of intent.
The U.S. Army Corps of Engineers, Sacramento District (Corps), intends to prepare a draft Environmental Impact Statement (DEIS) for the general reevaluation of the Sacramento River Flood Control Project, California. The Corps will serve as the lead agency for compliance with the National Environmental Policy Act (NEPA). The general reevaluation is assessing opportunities to restore ecosystem function along the Sacramento River and improve flood risk reduction capabilities of the flood conveyance system originally constructed in 1917. The system is located along the Sacramento River, from Elder Creek near Tehama to its confluence with the San Joaquin River in the Sacramento-San Joaquin Delta near Collinsville. System features are also located along a number of tributaries, sloughs, and bypass channels, including the Feather River, American River, Sutter Bypass, and Yolo Bypass.
Written comments regarding the scope of the general reevaluation and DEIS should be received by the Corps on or before November 23, 2015.
Send written comments and suggestions concerning this general reevaluation and DEIS to Mr. Dan Artho, U.S. Army Corps of Engineers, Sacramento District, Attn: Planning Division (CESPK-PD), 1325 J Street, Sacramento, CA 95814 or via email at
Mr. Dan Artho via telephone at (916) 557-7723, email at
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b. Issues that will be analyzed in depth in the DEIS include effects on hydrology and hydraulics, vegetation and wildlife, special-status species, water quality, air quality, socioeconomic conditions, transportation, agricultural resources, hazardous materials, and cultural resources. Other issues may include geology, soils, topography, noise, esthetics, climate and recreation. This is a large geographic extent with many technical, physical, biological, and social complexities associated with it.
c. The Corps will consult with the U.S. Fish and Wildlife Service and the National Marine Fisheries Service to comply with the Endangered Species Act and the Fish and Wildlife Coordination Act. The Corps will also consult with the State Historic Preservation Officer to comply with the National Historic Preservation Act and coordinate with the U.S. Bureau of Indian Affairs to establish consultation requirements with tribes having trust assets and tribal interests that could be affected by the general reevaluation's outcome.
d. A 45-day review period will be allowed for all interested agencies and individuals to review and comment on the DEIS. All interested persons are encouraged to respond to this notice and provide a current address if they wish to be contacted about the DEIS.
4.
Office of Science, Department of Energy.
Notice of partially-closed meeting.
This notice sets forth the schedule and summary agenda for a partially-closed meeting of the President's Council of Advisors on Science and Technology (PCAST), and describes the functions of the Council. The Federal Advisory Committee Act (Pub. L. 92-463, 86 Stat. 770) requires that public notice of these meetings be announced in the
November 20, 2015, 9:00 a.m. to 12:00 p.m.
National Academy of Sciences, 2101 Constitution Avenue NW., Washington, DC in the Lecture Room.
Information regarding the meeting agenda, time, location, and how to register for the meeting is available on the PCAST Web site at:
The President's Council of Advisors on Science and Technology (PCAST) is an advisory group of the nation's leading scientists and engineers, appointed by the President to augment the science and technology advice available to him from inside the White House, cabinet departments, and other Federal agencies. See the Executive Order at
The public comment period for this meeting will take place on November 20, 2015 at a time specified in the meeting agenda posted on the PCAST Web site at
Please note that because PCAST operates under the provisions of FACA, all public comments and/or presentations will be treated as public documents and will be made available for public inspection, including being posted on the PCAST Web site.
Take notice that the Commission received the following electric corporate filings:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and § 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
The Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC) will hold a joint meeting on Wednesday, October 21, 2015 at the headquarters of the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426. The meeting is expected to begin at 9:00 a.m. and conclude at approximately 11:30 a.m. Eastern Time. Members of the public may attend the open session. Commissioners from both agencies are expected to participate.
The format for the joint meeting will consist of discussions between the two sets of Commissioners following presentations by their respective staffs. In addition, representatives of the North American Electric Reliability Corporation (NERC) will attend and participate in this meeting.
The technical conference will be transcribed. Transcripts of the technical conference will be available for a fee from Ace-Federal Reporters, Inc. (202) 347-3700. There will be a free webcast of the conference. The webcast will allow persons to listen to the technical conference, but not participate. Anyone with Internet access can listen to the conference by navigating to the Calendar of Events at
Pre-registration is not required but is highly encouraged for those attending in person. Attendees may register in advance at the following Web page:
Commission conferences are accessible under section 508 of the Rehabilitation Act of 1973. For accessibility accommodations please send an email to
Questions about the meeting should be directed to Sarah McKinley at
Take notice that on October 1, 2015, Dominion Transmission, Inc. (DTI) 120 Tredegar Street, Richmond, VA, filed an application pursuant to section 7(b) of the Natural Gas Act (NGA) and the Federal Energy Regulatory Commission's (Commission) regulations seeking authorization to: (1) Abandon
Any questions regarding this application should be directed Machelle F. Grim, Dominion Resources Services, Inc., 701 East Cary Street, Richmond, VA 23219, or call (804) 771-3805, or fax (804) 771-4804, or by email:
Pursuant to section 157.9 of the Commission's rules, 18 CFR 157.9, within 90 days of this Notice the Commission staff will either: Complete its environmental assessment (EA) and place it into the Commission's public record (eLibrary) for this proceeding; or issue a Notice of Schedule for Environmental Review. If a Notice of Schedule for Environmental Review is issued, it will indicate, among other milestones, the anticipated date for the Commission staff's issuance of the final environmental impact statement (FEIS) or EA for this proposal. The filing of the EA in the Commission's public record for this proceeding or the issuance of a Notice of Schedule for Environmental Review will serve to notify federal and state agencies of the timing for the completion of all necessary reviews, and the subsequent need to complete all federal authorizations within 90 days of the date of issuance of the Commission staff's FEIS or EA.
There are two ways to become involved in the Commission's review of this project. First, any person wishing to obtain legal status by becoming a party to the proceedings for this project should, on or before the comment date stated below file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, a motion to intervene in accordance with the requirements of the Commission's Rules of Practice and Procedure (18 CFR 385.214 or 385.211) and the Regulations under the NGA (18 CFR 157.10). A person obtaining party status will be placed on the service list maintained by the Secretary of the Commission and will receive copies of all documents filed by the applicant and by all other parties. A party must submit 7 copies of filings made in the proceeding with the Commission and must mail a copy to the applicant and to every other party. Only parties to the proceeding can ask for court review of Commission orders in the proceeding.
However, a person does not have to intervene in order to have comments considered. The second way to participate is by filing with the Secretary of the Commission, as soon as possible, an original and two copies of comments in support of or in opposition to this project. The Commission will consider these comments in determining the appropriate action to be taken, but the filing of a comment alone will not serve to make the filer a party to the proceeding. The Commission's rules require that persons filing comments in opposition to the project provide copies of their protests only to the party or parties directly involved in the protest.
Persons who wish to comment only on the environmental review of this project should submit an original and two copies of their comments to the Secretary of the Commission. Environmental commentors will be placed on the Commission's environmental mailing list, will receive copies of the environmental documents, and will be notified of meetings associated with the Commission's environmental review process. Environmental commentors will not be required to serve copies of filed documents on all other parties. However, the non-party commentors will not receive copies of all documents filed by other parties or issued by the Commission (except for the mailing of environmental documents issued by the Commission) and will not have the right to seek court review of the Commission's final order.
The Commission strongly encourages electronic filings of comments, protests and interventions in lieu of paper using the “eFiling” link at
Comment Date: 5:00 p.m. Eastern Time on November 6, 2015.
Section 309(a) of the Clean Air Act requires that EPA make public its comments on EISs issued by other Federal agencies. EPA's comment letters on EISs are available at:
Environmental Protection Agency (EPA).
Notice.
EPA is required under the Toxic Substances Control Act (TSCA) to publish in the
Comments identified by the specific PMN number or TME number, must be received on or before November 23, 2015.
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPPT-2015-0183, and the specific PMN number or TME number for the chemical related to your comment, by one of the following methods:
•
•
•
Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at
This action is directed to the public in general. As such, the Agency has not attempted to describe the specific entities that this action may apply. Although others may be affected, this action applies directly to the submitter of the PMNs addressed in this action.
1.
2.
This document provides receipt and status reports, which cover the period from August 2, 2015 to August 31, 2015, and consists of the PMNs and TMEs both pending and/or expired, and the NOCs to manufacture a new chemical that the Agency has received under TSCA section 5 during this time period.
Under TSCA, 15 U.S.C. 2601
Anyone who plans to manufacture or import a new chemical substance for a non-exempt commercial purpose is required by TSCA section 5 to provide EPA with a PMN before initiating the activity. Section 5(h)(1) of TSCA authorizes EPA to allow persons, upon application, to manufacture (includes import) or process a new chemical substance, or a chemical substance subject to a significant new use rule (SNUR) issued under TSCA section 5(a), for “test marketing” purposes, which is referred to as a test marketing exemption, or TME. For more information about the requirements applicable to a new chemical go to:
Under TSCA sections 5(d)(2) and 5(d)(3), EPA is required to publish in the
As used in each of the tables, (S) indicates that the information in the table is the specific information provided by the submitter, and (G) indicates that the information in the table is generic information because the specific information provided by the submitter was claimed as CBI.
For the PMNs received by EPA during this period, Table 1 provides the following information (to the extent that such information is not claimed as CBI). The EPA case number assigned to the PMN, the date the PMN was received by EPA, the projected end date for EPA's review of the PMN, the submitting manufacturer/importer, the potential uses identified by the manufacturer/importer in the PMN, and the chemical identity.
For the TMEs received by EPA during this period, Table 2 provides the following information (to the extent that such information is not claimed as CBI). The EPA case number assigned to the TME, the date the TME was received by EPA, the projected end date for EPA's review of the TME, the submitting manufacturer/importer, the potential uses identified by the manufacturer/importer in the TME, and the chemical identity.
For the NOCs received by EPA during this period, Table 3 provides the following information (to the extent that such information is not claimed as CBI). The EPA case number assigned to the NOC, the date the NOC was received by EPA, the projected end date for EPA's review of the NOC, and chemical identity.
15 U.S.C. 2601
Environmental Protection Agency (EPA).
Notice.
Notice is hereby given that the Environmental Protection Agency has determined that, in accordance with the provisions of the Federal Advisory Committee Act (FACA), 5 U.S.C. App.2., the Pesticide Program Dialogue Committee (PPDC) is a necessary committee which is in the public interest. Accordingly, PPDC will be renewed for an additional two-year period. The purpose of PPDC is to provide advice and recommendations to the EPA Administrator on issues associated with regulatory development and reform initiatives, evolving public policy and program implementation issues, and science issues associated with evaluating and reducing risks from use of pesticides.
Dea Zimmerman, Designated Federal Officer, Pesticide Program Dialogue Committee (PPDC), U.S. EPA, (mail code LC-8J), 77 W. Jackson Boulevard, Chicago, IL 60604, telephone number: (312) 353-6344; email address:
You may be potentially affected by this action if you work in in agricultural settings or if you are concerned about implementation of the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA); the Federal Food, Drug, and Cosmetic Act (FFDCA); and the amendments to both of these major pesticide laws by the Food Quality Protection Act (FQPA) of 1996; the Pesticide Registration Improvement Act, and the Endangered Species Act. Potentially affected entities may include, but are not limited to: Agricultural workers and farmers; pesticide industry and trade associations; environmental, consumer, and farm worker groups; pesticide users and growers; animal rights groups; pest consultants; State, local, and tribal governments; academia; public health organizations; and the public. If you have questions regarding the applicability of this action to a particular entity, consult the person listed under
The docket for this action, identified by docket identification (ID) number EPA-HQ-OPP-2015-0651, is available at
5 U.S.C. App.2.
This is to provide notice of filing and to invite comments on or before November 13, 2015, with regard to the Petition described below.
Pacific International Lines (Private) Limited (PIL) and Mariana Express Lines Pte. Ltd. (MELL) (Petitioners), have petitioned the Commission pursuant to 46 CFR 502.74, for an exemption “equivalent to that contained in 46 CFR 535.307.” The Commission's regulations at 46 CFR 535.307 exempt agreements between or among wholly owned subsidiaries from the filing requirements of the Shipping Act. Specifically, Petitioners state that on March 11, 2015, PIL acquired sixty-five (65%) percent of the shares of MELL. Petitioners assert that FMC law and regulations would likely require PIL and MELL to file a number of agreements between themselves with the FMC, delay and what should be routine day-to-day decisions between a parent and its subsidiary.
The Petition in its entirety will be posted on the Commission's Web site at
In order for the Commission to make a thorough evaluation of the Petition, interested persons are requested to submit views or arguments in reply to the Petition no later than November 13, 2015. Commenters must send an original and 5 copies to the Secretary, Federal Maritime Commission, 800 North Capitol Street NW., Washington, DC 20573-0001, and be served on Petitioner's counsel, Neal M. Mayer, Hoppel, Mayer & Coleman, 1050 Connecticut Avenue NW., 10th Floor, Washington, DC 20036. A text-searchable PDF copy of the reply must also be sent as an attachment to
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 November 9, 2015.
A. Federal Reserve Bank of Kansas City (Dennis Denney, Assistant Vice President) 1 Memorial Drive, Kansas City, Missouri 64198-0001:
1.
The companies listed in this notice have applied to the Board for approval, pursuant to the Bank Holding Company Act of 1956 (12 U.S.C. 1841
The applications listed below, as well as other related filings required by the Board, are available for immediate inspection at the Federal Reserve Bank indicated. The applications will also be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the standards enumerated in the BHC Act (12 U.S.C. 1842(c)). If the proposal also involves the acquisition of a nonbanking company, the review also includes whether the acquisition of the nonbanking company complies with the standards in section 4 of the BHC Act (12 U.S.C. 1843). Unless otherwise noted, nonbanking activities will be conducted throughout the United States.
Unless otherwise noted, comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than November 19, 2015.
A. Federal Reserve Bank of Kansas City (Dennis Denney, Assistant Vice President) 1 Memorial Drive, Kansas City, Missouri 64198-0001:
1.
Federal Retirement Thrift Investment Board Member Meeting, October 27, 2015, 8:30 a.m., In-Person Meeting.
This notice serves as a revision to the previously published Sunshine Notice dated October 19, 2015 and published on October 21, 2015 in the
Kimberly Weaver, Director, Office of External Affairs, (202) 942-1640.
Office of the Chief Information Officer; General Services Administration.
Updated notice.
GSA proposes to update a system of records subject to the Privacy Act of 1974, as amended, 5 U.S.C. 552a.
GSA Privacy Act Officer (ISP), General Services Administration, 1800 F Street NW., Washington, DC 20405.
Call the GSA Privacy Act Officer at 202-368-1852 or email
GSA is updating a system of records subject to the Privacy Act of 1974, 5 U.S.C. 552a. The notice provides updated information. Nothing in the notice will impact individuals' rights to access or amend their records in the systems of records.
HSPD-12 USAccess.
Records covered by this system are maintained by a contractor at the contractor's site.
The Personal Identity Verification Identity Management System (PIV IDMS) records will cover all participating agency employees, contractors and their employees, consultants, and volunteers who require routine, long-term access to federal facilities, information technology systems, and networks. The system also includes individuals authorized to perform or use services provided in agency facilities (
Enrollment records maintained in the PIV IDMS on individuals applying for the PIV program and a PIV credential through the GSA HSPD-12 managed service include the following data fields: Full name; Social Security Number; Applicant ID number, date of birth; current address; digital color photograph; fingerprints; biometric template (two fingerprints); organization/office of assignment; employee affiliation; work email address; work telephone number(s); office address; copies of identity source documents; employee status; military status; foreign national status; federal emergency response official status; law enforcement official status; results of background check; Government agency code; and PIV card issuance location. Records in the PIV IDMS needed for credential management for enrolled individuals in the PIV program include: PIV card serial number; digital certificate(s) serial number; PIV card issuance and expiration dates; PIV card PIN; Cardholder Unique Identifier (CHUID); and card management keys. Agencies may also choose to collect the following data at PIV enrollment which would also be maintained in the PIV IDMS: Physical characteristics (
5 U.S.C. 301; Federal Information Security Management Act of 2002 (44 U.S.C. 3554); E-Government Act of 2002 (Pub. L. 107-347, Sec. 203); Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et al.) and Government Paperwork Elimination Act (Pub. L. 105-277, 44 U.S.C. 3504 note); Homeland Security Presidential Directive 12 (HSPD-12), Policy for a Common Identification Standard for Federal Employees and Contractors, August 27, 2004.
The primary purposes of the system are: To ensure the safety and security of Federal facilities, systems, or information, and of facility occupants and users; to provide for interoperability and trust in allowing physical access to individuals entering Federal facilities; and to allow logical access to Federal information systems, networks, and resources on a government-wide basis.
In addition to those disclosures generally permitted under 5 U.S.C. Section 552a(b) of the Privacy Act, all or a portion of the records or information contained in this system may be disclosed outside GSA as a routine use pursuant to 5 U.S.C. 552a(b)(3) as follows:
a. To the Department of Justice (DOJ) when: (1) The agency or any component thereof; or (2) any employee of the agency in his or her official capacity; (3) any employee of the agency in his or her individual capacity where agency or the Department of Justice has agreed to represent the employee; or (4) the United States Government is a party to litigation or has an interest in such litigation, and by careful review, the agency determines that the records are both relevant and necessary to the litigation and the use of such records by DOJ and is therefore deemed by the agency to be for a purpose compatible with the purpose for which the agency collected the records.
b. To a court or adjudicative body in a proceeding when: (1) The agency or any component thereof; (2) any employee of the agency in his or her official capacity; (3) any employee of the agency in his or her individual capacity where the agency or the Department of Justice has agreed to represent the employee; or (4) the United States Government is a party to litigation or has an interest in such litigation, and by careful review, the agency determines that the records are both relevant and necessary to the litigation and the use of such records and is therefore deemed by the agency to be for a purpose that is compatible with the purpose for which the agency collected the records.
c. Except as noted on Forms SF 85, SF 85-P, and SF 86, when a record on its face, or in conjunction with other records, indicates a violation or potential violation of law, whether civil, criminal, or regulatory in nature, and whether arising by general statute or particular program statute, or by regulation, rule, or order issued pursuant thereto, disclosure may be made to the appropriate public authority, whether Federal, foreign, State, local, or tribal, or otherwise, responsible for enforcing, investigating or prosecuting such violation or charged with enforcing or implementing the statute, or rule, regulation, or order issued pursuant thereto, if the information disclosed is relevant to any enforcement, regulatory, investigative or prosecutorial responsibility of the receiving entity.
d. To a Member of Congress or to a Congressional staff member in response to an inquiry of the Congressional office made at the written request of the constituent about whom the record is maintained.
e. To the National Archives and Records Administration (NARA) or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 and 2906.
f. To agency contractors, grantees, or volunteers who have been engaged to assist the agency in the performance of a contract, service, grant, cooperative agreement, or other activity related to this system of records and who need to have access to the records in order to perform their activity. Recipients shall be required to comply with the requirements of the Privacy Act of 1974, as amended, 5 U.S.C. 552a, the Federal Information Security Management Act (Pub. L. 107-296), and associated OMB policies, standards and guidance from the National Institute of Standards and Technology, and the General Services Administration.
g. To a Federal agency, State, local, foreign, or tribal or other public authority, on request, in connection with the hiring or retention of an employee, the issuance or retention of a security clearance, the letting of a
h. To the Office of Management and Budget (OMB) when necessary to the review of private relief legislation pursuant to OMB Circular No. A-19.
i. To a Federal, State, or local agency, or other appropriate entities or individuals, or through established liaison channels to selected foreign governments, in order to enable an intelligence agency to carry out its responsibilities under the National Security Act of 1947, as amended; the CIA Act of 1949, as amended; Executive Order 12333 or any successor order; and applicable national security directives, or classified implementing procedures approved by the Attorney General and promulgated pursuant to such statutes, orders, or Directives.
j. To designated agency personnel for controlled access to specific records for the purposes of performing authorized audit or authorized oversight and administrative functions. All access is controlled systematically through authentication using PIV credentials based on access and authorization rules for specific audit and administrative functions.
k. To the Office of Personnel Management (OPM), the Office of Management and Budget (OMB), the Government Accountability Office (GAO), or other Federal agency in accordance with the agency's responsibility for evaluation of Federal personnel management.
l. To the Federal Bureau of Investigation for the FBI National Criminal History check.
m. To appropriate agencies, entities, and persons when (1) the Agency suspects or has confirmed that the security or confidentiality of information in the system of records has been compromised; (2) the Agency has determined that as a result of the suspected or confirmed compromise there is a risk of harm to economic or property interests, identity theft or fraud, or harm to the security or integrity of this system or other systems or programs (whether maintained by GSA or another agency or entity) that rely upon the compromised information; and (3) the disclosure made to such agencies, entities, and persons is reasonably necessary to assist in connection with GSA's efforts to respond to the suspected or confirmed compromise and prevent, minimize, or remedy such harm.
Records are stored in electronic media and in paper files.
Records may be retrieved by name of the individual, Cardholder Unique Identification Number, Applicant ID, Social Security Number, and/or by any other unique individual identifier.
Consistent with the requirements of the Federal Information Security Management Act (Pub. L. 107-296), and associated OMB policies, standards and guidance from the National Institute of Standards and Technology, and the General Services Administration, the GSA HSPD-12 managed service office protects all records from unauthorized access through appropriate administrative, physical, and technical safeguards. Access is restricted on a “need to know” basis, utilization of PIV Card access, secure VPN for Web access, and locks on doors and approved storage containers. Buildings have security guards and secured doors. All entrances are monitored through electronic surveillance equipment. The hosting facility is supported by 24/7 onsite hosting and network monitoring by trained technical staff. Physical security controls include: Indoor and outdoor security monitoring and surveillance; badge and picture ID access screening; biometric access screening. Personally identifiable information is safeguarded and protected in conformance with all Federal statutory and OMB guidance requirements. All access has role-based restrictions, and individuals with access privileges have undergone vetting and suitability screening. All data is encrypted in transit. While it is not contemplated, any system records stored on mobile computers or mobile devices will be encrypted. GSA maintains an audit trail and performs random periodic reviews to identify unauthorized access. Persons given roles in the PIV process must be approved by the Government and complete training specific to their roles to ensure they are knowledgeable about how to protect personally identifiable information.
Disposition of records will be according to NARA disposition authority N1-269-06-1 (pending).
Director, HSPD-12 Managed Service Office, Federal Acquisition Service (FAS), General Services Administration, 1800 F Street NW., 4th Floor, Washington, DC 20405.
A request for access to records in this system may be made by writing to the System Manager. When requesting notification of or access to records covered by this Notice, an individual should provide his/her full name, date of birth, agency name, and work location. An individual requesting notification of records must provide identity documents sufficient to satisfy the custodian of the records that the requester is entitled to access, such as a government-issued photo ID.
Same as Notification Procedure above.
Same as Notification Procedure above. State clearly and concisely the information being contested, the reasons for contesting it, and the proposed amendment to the information sought.
Employee, contractor, or applicant; sponsoring agency; former sponsoring agency; other Federal agencies; contract employer; former employer.
Centers for Medicare & Medicaid Services (CMS), HHS.
Notice.
This notice announces an expansion of the 3-year Medicare Prior Authorization Model for Repetitive Scheduled Non-Emergent Ambulance Transport in accordance with section 515(a) of the Medicare Access and CHIP Reauthorization Act of 2015. The model is being expanded to the states of Maryland, Delaware, the District of Columbia, North Carolina, West Virginia, and Virginia.
This expansion will begin on January 1, 2016 in Maryland, Delaware,
Angela Gaston, (410) 786-7409.
Questions regarding the Medicare Prior Authorization Model Expansion for Repetitive Scheduled Non-Emergent Ambulance Transport should be sent to
Medicare may cover ambulance services, including air ambulance (fixed-wing and rotary-wing) services, if the ambulance service is furnished to a beneficiary whose medical condition is such that other means of transportation are contraindicated. The beneficiary's condition must require both the ambulance transportation itself and the level of service provided in order for the billed service to be considered medically necessary.
Non-emergent transportation by ambulance is appropriate if either the—(1) beneficiary is bed-confined and it is documented that the beneficiary's condition is such that other methods of transportation are contraindicated; or (2) beneficiary's medical condition, regardless of bed confinement, is such that transportation by ambulance is medically required. Thus, bed confinement is not the sole criterion in determining the medical necessity of non-emergent ambulance transportation; rather, it is one factor that is considered in medical necessity determinations.
A repetitive ambulance service is defined as medically necessary ambulance transportation that is furnished in 3 or more round trips during a 10-day period, or at least 1 round trip per week for at least 3 weeks.
Medicare may cover repetitive, scheduled, non-emergent transportation by ambulance if the—(1) medical necessity requirements described previously are met; and (2) ambulance provider/supplier, before furnishing the service to the beneficiary, obtains a written order from the beneficiary's attending physician certifying that the medical necessity requirements are met (see 42 CFR 410.40(d)(1) and (2)).
In addition to the medical necessity requirements, the service must meet all other Medicare coverage and payment requirements, including requirements relating to the origin and destination of the transportation, vehicle and staff, and billing and reporting. Additional information about Medicare coverage of ambulance services can be found in 42 CFR 410.40, 410.41, and in the Medicare Benefit Policy Manual (Pub. 100-02), Chapter 10, at
According to a study published by the Government Accountability Office in October 2012, entitled “Costs and Medicare Margins Varied Widely; Transports of Beneficiaries Have Increased,”
Section 1115A of the Social Security Act (the Act) authorizes the Secretary to test innovative payment and service delivery models to reduce program expenditures, while preserving or enhancing the quality of care furnished to Medicare, Medicaid, and Children's Health Insurance Program beneficiaries.
Section 1115A(d)(1) of the Act authorizes the Secretary to waive such requirements of Titles XI and XVIII and of sections 1902(a)(1), 1902(a)(13), and 1903(m)(2)(A)(iii) of the Act as may be necessary solely for purposes of carrying out section 1115A of the Act with respect to testing models described in section 1115A(b) of the Act. For these models, consistent with this standard, we will waive such provisions of sections 1834(a)(15) and 1869(h) of the Act that limit our ability to conduct prior authorization. While these provisions are specific to durable medical equipment and physicians' services, we will waive any portion of these sections as well as any portion of 42 CFR 410.20(d), which implements section 1869(h) of the Act, that could be construed to limit our ability to conduct prior authorization. We have determined that the implementation of this model does not require the waiver of any fraud and abuse law, including sections 1128A, 1128B, and 1877 of the Act. Thus providers and suppliers affected by this model must comply with all applicable fraud and abuse laws.
In the November 14, 2014
Section 515(a) of the Medicare Access and CHIP Reauthorization Act of 2015 (MACRA) (Pub. L. 114-10), requires expansion of the previously referenced prior authorization model to cover, effective not later than January 1, 2016, states located in Medicare Administrative Contractor (MAC) regions L and 11 (consisting of Delaware, the District of Columbia, Maryland, New Jersey, Pennsylvania, North Carolina, South Carolina, West Virginia, and Virginia). As such, in accordance with section 515(a) of MACRA, our initial expansion of the prior authorization model for repetitive scheduled non-emergent ambulance transport will include six additional states: Delaware, the District of Columbia, Maryland, North Carolina, Virginia, and West Virginia. This expansion will begin on January 1, 2016. The model will end in all states on December 1, 2017. Prior authorization will not apply to or be given for services furnished after that date.
We will continue to test whether prior authorization helps reduce
We will continue to use this prior authorization process to help ensure that all relevant clinical or medical documentation requirements are met before services are furnished to beneficiaries and before claims are submitted for payment. This prior authorization process further helps to ensure that payment complies with Medicare documentation, coverage, payment, and coding rules.
The use of prior authorization does not create new clinical documentation requirements. Instead, it requires the same information that is already required to support Medicare payment, just earlier in the process. Prior authorization allows providers and suppliers to address coverage issues prior to furnishing services.
The prior authorization process under this model will apply in the additional six states listed previously for the following codes for Medicare payment:
• A0426 Ambulance service, advanced life support, non-emergency transport, Level 1 (ALS1).
• A0428 Ambulance service, BLS, non-emergency transport.
While prior authorization in the additional six states is not needed for the mileage code, A0425, a prior authorization decision for an A0426 or A0428 code will automatically include the associated mileage code.
Prior to the start of the expansion, we will conduct (and thereafter will continue to conduct) outreach and education to ambulance providers/suppliers, as well as beneficiaries, through such methods as the issuance of an operational guide, frequently asked questions (FAQs) on our Web site, a beneficiary mailing, a physician letter explaining the ambulance providers/suppliers' need for the proper documentation, and educational events and materials issued by the MACs. Additional information about the implementation of the prior authorization model is available on the CMS Web site at
Under this model, an ambulance provider/supplier or beneficiary is encouraged to submit to the MAC a request for prior authorization along with all relevant documentation to support Medicare coverage of a repetitive scheduled non-emergent ambulance transport. Submitting a prior authorization request is voluntary. However, if prior authorization has not been requested by the fourth round trip in a 30-day period, the claims will be stopped for pre-payment review.
In order to be provisionally affirmed, the request for prior authorization must meet all applicable rules and policies, and any local coverage determination (LCD) requirements for ambulance transport claims. A provisional affirmation is a preliminary finding that a future claim submitted to Medicare for the service likely meets Medicare's coverage, coding, and payment requirements. After receipt of all relevant documentation, the MACs will make every effort to conduct a review and postmark the notification of their decision on a prior authorization request within 10 business days for an initial submission. Notification will be provided to the ambulance provider/supplier and to the beneficiary. If a subsequent prior authorization request is submitted after a non-affirmative decision on an initial prior authorization request, the MACs will make every effort to conduct a review and postmark the notification of their decision on the request within 20 business days.
An ambulance provider/supplier or beneficiary may request an expedited review when the standard timeframe for making a prior authorization decision could jeopardize the life or health of the beneficiary. If the MAC agrees that the standard review timeframe would put the beneficiary at risk, the MAC will make reasonable efforts to communicate a decision within 2 business days of receipt of all applicable Medicare-required documentation. As this model is for non-emergent services only, we expect requests for expedited reviews to be extremely rare.
A provisional affirmative prior authorization decision may affirm a specified number of trips within a specific amount of time. The prior authorization decision, justified by the beneficiary's condition, may affirm up to 40 round trips (which equates to 80 one-way trips) per prior authorization request in a 60-day period. Alternatively, a provisional affirmative prior authorization decision may affirm less than 40 round trips in a 60-day period, or may affirm a request that seeks to provide a specified number of transports (40 round trips or less) in less than a 60-day period. A provisional affirmative decision can be for all or part of the requested number of trips. Transports exceeding 40 round trips (or 80 one-way trips) in a 60-day period require an additional prior authorization request.
The following describes examples of various prior authorization scenarios:
•
•
•
•
++ If the claim is determined not to be medically necessary or to be insufficiently documented, the claim will be denied, and all current policies and procedures regarding liability for payment will apply. The ambulance provider/supplier or the beneficiary or both can appeal the claim denial if they believe the denial was inappropriate.
++ If the claim is determined to be payable, it will be paid.
Under the model, we will work to limit any adverse impact on beneficiaries and to educate beneficiaries about the process. If a prior authorization request is not affirmed, and the claim is still submitted by the provider/supplier, the claim will be denied in full, but beneficiaries will continue to have all applicable administrative appeal rights.
Only one prior authorization request per beneficiary per designated time period can be provisionally affirmed. If the initial provider/supplier cannot complete the total number of prior authorized transports (for example, the initial ambulance company closes or no longer services that area), the initial request is cancelled. In this situation, a subsequent prior authorization request may be submitted for the same beneficiary and must include the required documentation in the submission. If multiple ambulance providers/suppliers are providing transports to the beneficiary during the same or overlapping time period, the prior authorization decision will only cover the provider/supplier indicated in the provisionally affirmed prior authorization request. Any provider/supplier submitting claims for repetitive scheduled non-emergent ambulance transports for which no prior authorization request is recorded will be subject to 100 percent pre-payment medical review of those claims.
Additional information is available on the CMS Web site at
Section 1115A(d)(3) of the Act, as added by section 3021 of the Affordable Care Act, states that chapter 35 of title 44, United States Code (the Paperwork Reduction Act of 1995), shall not apply to the testing and evaluation of models or expansion of such models under this section. Consequently, this document need not be reviewed by the Office of Management and Budget under the authority of the Paperwork Reduction Act of 1995.
This document announces an expansion of the 3-year Medicare Prior Authorization Model for Repetitive Scheduled Non-Emergent Ambulance Transport. Therefore, there are no regulatory impact implications associated with this notice.
Section 1115A of the Social Security Act.
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a collection of information entitled “MedWatch: The Food and Drug Administration Medical Products Reporting Program” has been approved by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995.
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002,
On June 11, 2015, the Agency submitted a proposed collection of information entitled “MedWatch: The Food and Drug Administration Medical Products Reporting Program” to OMB for review and clearance under 44 U.S.C. 3507. An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. OMB has now approved the information collection and has assigned OMB control number 0910-0291. The approval expires on September 30, 2018. A copy of the supporting statement for this information collection is available on the Internet at
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a collection of information entitled “Medical Device Labeling Regulations” has been approved by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995.
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002,
On January 30, 2015, the Agency submitted a proposed collection of information entitled “Medical Device Labeling Regulations” to OMB for review and clearance under 44 U.S.C. 3507. An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. OMB has now approved the information collection and has assigned OMB control number 0910-0485. The approval expires on September 30, 2018. A copy of the supporting statement for this information collection is available on the Internet at
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing an opportunity for public comment on the proposed collection of certain information by the Agency. Under the Paperwork Reduction Act of 1995 (the PRA), Federal Agencies are required to publish notice in the
Submit either electronic or written comments on the collection of information by December 22, 2015.
You may submit comments as follows:
Submit electronic comments in the following way:
•
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).
Submit written/paper submissions as follows:
•
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.” The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002,
Under the PRA (44 U.S.C. 3501-3520), Federal Agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes Agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal Agencies to provide a 60-day notice in the
With respect to the following collection of information, FDA invites comments on these topics: (1) Whether the proposed collection of information is necessary for the proper performance of FDA's functions, including whether the information will have practical utility; (2) the accuracy of FDA's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
FDA's investigational device regulations are intended to encourage the development of new, useful devices in a manner that is consistent with public health, safety, and compliant with ethical standards. Investigators should have freedom to pursue the least burdensome means of accomplishing this goal. However, to ensure that the balance is maintained between product development and the protection of public health, safety, and ethical standards, FDA has established human subject protection regulations addressing requirements for informed consent and institutional review board (IRB) review that apply to all FDA-regulated clinical investigations involving human subjects. In particular, informed consent requirements further both safety and ethical considerations by allowing potential subjects to consider both the physical and privacy risks they face if they agree to participate in a trial.
Under FDA regulations, clinical investigations using human specimens conducted in support of premarket submissions to FDA are considered human subject investigations (see 21 CFR 812.3(p)). Many investigational device studies are exempt from most provisions of part 812, Investigational Device Exemptions, under 21 CFR 812.2(c)(3), but FDA's regulations for the protection of human subjects (21 CFR parts 50 and 56) apply to all clinical investigations that are regulated by FDA (see 21 CFR 50.1, 21 CFR 56.101, 21 U.S.C. 360j(g)(3)(A), and 21 U.S.C. 360j(g)(3)(D)).
FDA regulations do not contain exceptions from the requirements of informed consent on the grounds that the specimens are not identifiable or that they are remnants of human specimens collected for routine clinical care or analysis that would otherwise have been discarded. Nor do FDA regulations allow IRBs to decide whether or not to waive informed consent for research involving leftover or unidentifiable specimens.
In a level 1 guidance document, entitled “Guidance on Informed Consent for In Vitro Diagnostic Device Studies Using Leftover Human Specimens that are Not Individually Identifiable,” issued under the Good Guidances Practices regulation, 21 CFR 10.115, FDA outlines the circumstances in which it intends to exercise enforcement discretion as to the informed consent regulations for clinical investigators, sponsors, and IRBs.
The recommendations of the guidance impose a minimal burden on industry. FDA estimates that 700 studies will be affected annually. Each study will result in one annual record, estimated to take 4 hours to complete. This results in a total recordkeeping burden of 2,800 hours (700 × 4 = 2,800).
FDA estimates the burden of this collection of information as follows:
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a collection of information entitled “Medical Device Recall Authority” has been approved by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995.
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002,
On June 15, 2015, the Agency submitted a proposed collection of information entitled “Medical Device Recall Authority” to OMB for review and clearance under 44 U.S.C. 3507. An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. OMB has now approved the information collection and has assigned OMB control number 0910-0432. The approval expires on September 30, 2018. A copy of the supporting statement for this information collection is available on the Internet at
Presidential Commission for the Study of Bioethical Issues, Office of the Assistant Secretary for Health, Office of the Secretary, Department of Health and Human Services.
Notice of meeting.
The Presidential Commission for the Study of Bioethical Issues (the Commission) will conduct its twenty third meeting on November 17, 2015. At this meeting, the Commission will continue to discuss the role of deliberation and deliberative methods to engage the public and inform consideration in bioethics, and how to integrate pubic dialogue into the bioethics conversation; bioethics education as a forum for fostering deliberative skills, and preparing students to participate in public dialogue in bioethics; goals and methods of bioethics education; and integrating bioethics education across a
The meeting will take place November 17, 2015, from 9 a.m. to approximately 5 p.m.
Hilton Arlington Hotel, 950 North Stafford Street, Arlington, VA 22203.
Lisa M. Lee, Executive Director, Presidential Commission for the Study of Bioethical Issues, 1425 New York Avenue NW., Suite C-100, Washington, DC 20005. Telephone: 202-233-3960. Email:
Pursuant to the Federal Advisory Committee Act of 1972, Public Law 92-463, 5 U.S.C. app. 2, notice is hereby given for the twenty-third meeting of the Commission. The meeting will be open to the public with attendance limited to space available. The meeting will also be webcast at
Under authority of Executive Order 13521, dated November 24, 2009, the President established the Commission. The Commission is an expert panel of not more than 13 members who are drawn from the fields of bioethics, science, medicine, technology, engineering, law, philosophy, theology, or other areas of the humanities or social sciences. The Commission advises the President on bioethical issues arising from advances in biomedicine and related areas of science and technology. The Commission seeks to identify and promote policies and practices that ensure scientific research, health care delivery, and technological innovation are conducted in a socially and ethically responsible manner.
The main agenda items for the Commission's twenty-third meeting are to continue discussing the role of deliberation and deliberative methods to engage the public in bioethics, and how to integrate pubic dialogue into the bioethics conversation; bioethics education as a forum for fostering deliberative skills, and preparing students to participate in public dialogue in bioethics; goals and methods of bioethics education; and integrating bioethics education across a range of professional disciplines and educational levels. The draft meeting agenda and other information about the Commission, including information about access to the webcast, will be available at
The Commission welcomes input from anyone wishing to provide public comment on any issue before it. Respectful consideration of opposing views and active participation by citizens in public exchange of ideas enhances overall public understanding of the issues at hand and conclusions reached by the Commission. The Commission is particularly interested in receiving comments and questions during the meeting that are responsive to specific sessions. Written comments will be accepted at the registration desk and comment forms will be provided to members of the public in order to write down questions and comments for the Commission as they arise. To accommodate as many individuals as possible, the time for each question or comment may be limited. If the number of individuals wishing to pose a question or make a comment is greater than can reasonably be accommodated during the scheduled meeting, the Commission may make a random selection.
Written comments will also be accepted in advance of the meeting and are especially welcome. Please address written comments by email to
Anyone planning to attend the meeting who needs special assistance, such as sign language interpretation or other reasonable accommodations, should notify Esther Yoo by telephone at (202) 233-3960, or email at
Office of the Assistant Secretary for Health, Office of the Secretary, Department of Health and Human Services.
Notice.
As stipulated by the Federal Advisory Committee Act, the U.S. Department of Health and Human Services is hereby giving notice that the Advisory Committee on Blood and Tissue Safety and Availability (ACBTSA) will hold a meeting. The meeting will be open to the public.
The meeting will take place Monday, November 9, 2015, from 8:00 a.m.-4:30 p.m. and Tuesday, November 10, 2015, from 8:00 a.m.-4:00 p.m.
Veterans' Health Administration National Conference Center, 2011 Crystal Drive, 1st floor Conference Center, Crystal City, VA 22202.
Mr. James Berger, Designated Federal Officer for the ACBTSA, Senior Advisor for Blood and Tissue Policy, Office of the Assistant Secretary for Health, Department of Health and Human Services, 1101 Wootton Parkway, Suite 250, Rockville, MD 20852. Phone: (240) 453-8803; Fax (240) 453-8456; Email
The ACBTSA provides advice to the Secretary through the Assistant Secretary for Health. The Committee advises on a range of policy issues to include: (1) Identification of public health issues through surveillance of blood and tissue safety issues with national biovigilance data tools; (2) identification of public health issues that affect availability of blood, blood products, and tissues; (3) broad public health, ethical and legal issues related to the safety of blood, blood products, and tissues; (4) the impact of various economic factors (
In December 2013, the Committee made recommendations regarding the blood system. At that time, the Committee expressed concern about the ongoing reductions in blood use, the number of large scale consolidations occurring, the cost recovery issues for blood centers, and the potential effects on safety and innovation due to instability. Past recommendations made by the ACBTSA may be viewed at
This meeting will provide a focused examination of the mechanisms to fund recently approved blood safety innovations, such as pathogen
The public will have an opportunity to present their views to the Committee during a public comment session scheduled for November 10, 2015. Comments will be limited to five minutes per speaker and must be pertinent to the discussion. Pre-registration is required for participation in the public comment session. Any member of the public who would like to participate in this session is required to contact the Designated Federal Officer at his/her earliest convenience to register for time (limited to 5 minutes); registration must be completed prior to close of business on November 2, 2015. If it is not possible to provide 30 copies of the material to be distributed at the meeting, then individuals are requested to provide a minimum of one (1) copy of the document(s) to be distributed prior to the close of business on November 2, 2015. It is also requested that any member of the public who wishes to provide comments to the Committee utilizing electronic data projection submit the necessary material to the Designated Federal Officer prior to the close of business on November 2, 2015.
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.
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.
Contact Person: John H Newman, Ph.D., Scientific Review Officer, Center for Scientific Review, National Institutes of Health, 6701 Rockledge Drive, Room 3222, MSC 7808, Bethesda, MD 20892, (301) 435-0628,
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, NICHD.
The meeting will be open to the public as indicated below, with the attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
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 Eunice Kennedy Shriver National Institute of Child Health and Human Development, including consideration of personnel qualifications and performance, and the competence of individual investigators, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Information is also available on the Institute's/Center's home page:
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 materials, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The contract proposals and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the contract proposals, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Coast Guard, DHS.
Sixty-day notice requesting comments.
In compliance with the Paperwork Reduction Act of 1995, the
Comments must reach the Coast Guard on or before December 22, 2015.
You may submit comments identified by Coast Guard docket number [USCG-2015-0909] to the Coast Guard using the Federal eRulemaking Portal at
A copy of the ICR is available through the docket on the Internet at
Mr. Anthony Smith, Office of Information Management, telephone 202-475-3532, or fax 202-372-8405, for questions on these documents.
This Notice relies on the authority of the Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended. An ICR is an application to OIRA seeking the approval, extension, or renewal of a Coast Guard collection of information (Collection). The ICR contains information describing the Collection's purpose, the Collection's likely burden on the affected public, an explanation of the necessity of the Collection, and other important information describing the Collection. There is one ICR for each Collection.
The Coast Guard invites comments on whether this ICR should be granted based on the Collection being necessary for the proper performance of Departmental functions. In particular, the Coast Guard would appreciate comments addressing: (1) The practical utility of the Collection; (2) the accuracy of the estimated burden of the Collection; (3) ways to enhance the quality, utility, and clarity of information subject to the Collection; and (4) ways to minimize the burden of the Collection on respondents, including the use of automated collection techniques or other forms of information technology. In response to your comments, we may revise this ICR or decide not to seek approval of revisions of the Collection. We will consider all comments and material received during the comment period.
We encourage you to respond to this request by submitting comments and related materials. Comments must contain the OMB Control Number of the ICR and the docket number of this request, [USCG-2015-0909], and must be received by December 22, 2015.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
1.
The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended.
Coast Guard, DHS.
Sixty-day notice requesting comments.
In compliance with the Paperwork Reduction Act of 1995, the U.S. Coast Guard intends to submit an Information Collection Request (ICR) to the Office of Management and Budget (OMB), Office of Information and Regulatory Affairs (OIRA), requesting approval of revisions to the following collection of information: 1625-0001, Marine Casualty Information & Periodic Chemical Drug and Alcohol Testing of Commercial Vessel Personnel. Our ICR describe the information we seek to collect from the public. Before submitting this ICR to OIRA, the Coast Guard is inviting comments as described below.
Comments must reach the Coast Guard on or before December 22, 2015.
You may submit comments identified by Coast Guard docket number [USCG-2015-0910] to the Coast Guard using the Federal eRulemaking Portal at
A copy of the ICR is available through the docket on the Internet at
Mr. Anthony Smith, Office of Information Management, telephone 202-475-3532, or fax 202-372-8405, for questions on these documents.
This Notice relies on the authority of the Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended. An ICR is an application to OIRA seeking the approval, extension, or renewal of a Coast Guard collection of information (Collection). The ICR contains information describing the Collection's purpose, the Collection's likely burden on the affected public, an explanation of the necessity of the Collection, and other important information describing the Collection. There is one ICR for each Collection.
The Coast Guard invites comments on whether this ICR should be granted based on the Collection being necessary for the proper performance of Departmental functions. In particular, the Coast Guard would appreciate comments addressing: (1) The practical utility of the Collection; (2) the accuracy of the estimated burden of the Collection; (3) ways to enhance the quality, utility, and clarity of information subject to the Collection; and (4) ways to minimize the burden of the Collection on respondents, including the use of automated collection techniques or other forms of information technology. In response to your comments, we may revise this ICR or decide not to seek approval of revisions of the Collection. We will consider all comments and material received during the comment period.
We encourage you to respond to this request by submitting comments and related materials. Comments must contain the OMB Control Number of the ICR and the docket number of this request, [USCG-2015-0910], and must be received by December 22, 2015.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
1.
The resulting proposal to revise these forms, which includes revising the title name of the form and taking certain sections of the CG-2692 and moving them to two new Addendum forms (facilitates multiple entry capability not currently available) have been drafted with the following goals in mind:
• Reduce the overall amount of information required to be entered to submit reports for marine casualties while still meeting all statutory and regulatory requirements.
• Clarify what types of incidents require the submission of the written report and seek the inclusion of additional information, entered on one or more of the Addendum forms, only when it is necessary.
• Reformat and organize the information on the forms such that it is more adaptable to the development of an alternate electronic means of submission.
The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended.
Coast Guard, DHS.
Thirty-day notice requesting comments.
In compliance with the Paperwork Reduction Act of 1995 the U.S. Coast Guard is forwarding an Information Collection Request (ICR), abstracted below, to the Office of Management and Budget (OMB), Office of Information and Regulatory Affairs (OIRA), requesting approval of a revision to the following collection of information: 1625-0035, Title 46 CFR Subchapter Q: Lifesaving, Electrical, Engineering and Navigation Equipment, Construction and Materials & Marine Sanitation Devices (33 CFR part 159). Our ICR describe the information we seek to collect from the public. Review and comments by OIRA ensure we only impose paperwork burdens commensurate with our performance of duties.
Comments must reach the Coast Guard and OIRA on or before November 23, 2015.
You may submit comments identified by Coast Guard docket number [USCG-2015-0630] to the Coast Guard using the Federal eRulemaking Portal at
(1)
(2)
(3)
A copy of the ICR is available through the docket on the Internet at
Mr. Anthony Smith, Office of Information Management, telephone 202-475-3532, or fax 202-372-8405, for questions on these documents.
This Notice relies on the authority of the Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended. An ICR is an application to OIRA seeking the approval, extension, or renewal of a Coast Guard collection of information (Collection). The ICR contains information describing the Collection's purpose, the Collection's likely burden on the affected public, an explanation of the necessity of the Collection, and other important information describing the Collection. There is one ICR for each Collection. The Coast Guard invites comments on whether this ICR should be granted based on the Collection being necessary for the proper performance of Departmental functions. In particular, the Coast Guard would appreciate comments addressing: (1) The practical utility of the Collection; (2) the accuracy of the estimated burden of the Collection; (3) ways to enhance the quality, utility, and clarity of information subject to the Collection; and (4) ways to minimize the burden of the Collection on respondents, including the use of automated collection techniques or other forms of information technology. These comments will help OIRA determine whether to approve the ICR referred to in this Notice.
We encourage you to respond to this request by submitting comments and related materials. Comments to Coast Guard or OIRA must contain the OMB Control Number of the ICR. They must also contain the docket number of this request, [USCG-2015-0630], and must be received by November 23, 2015.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
OIRA posts its decisions on ICRs online at
This request provides a 30-day comment period required by OIRA. The Coast Guard has published the 60-day notice (80 FR 45671, July 31, 2015) required by 44 U.S.C. 3506(c)(2). That Notice elicited no comments. Accordingly, no changes have been made to the Collections.
1.
The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended.
Coast Guard, DHS.
Thirty-day notice requesting comments.
In compliance with the Paperwork Reduction Act of 1995 the U.S. Coast Guard is forwarding an Information Collection Request (ICR), abstracted below, to the Office of Management and Budget (OMB), Office of Information and Regulatory Affairs (OIRA), requesting an extension of its approval for the following collection of information: 1625-0095, Oil and Hazardous Material Pollution Prevention and Safety Records, Equivalents/Alternatives and Exemptions without change.
Our ICR describe the information we seek to collect from the public. Review and comments by OIRA ensure we only impose paperwork burdens commensurate with our performance of duties.
Comments must reach the Coast Guard and OIRA on or before November 23, 2015.
You may submit comments identified by Coast Guard docket number [USCG-2015-0475] to the Coast Guard using the Federal eRulemaking Portal at
(1)
(2)
(3)
A copy of the ICR is available through the docket on the Internet at
Contact Mr. Anthony Smith, Office of Information Management, telephone 202-475-3532, or fax 202-372-8405, for questions on these documents.
This Notice relies on the authority of the Paperwork Reduction Act of 1995; 44 U.S.C. chapter 35, as amended. An ICR is an application to OIRA seeking the approval, extension, or renewal of a Coast Guard collection of information (Collection). The ICR contains information describing the Collection's purpose, the Collection's likely burden on the affected public, an explanation of the necessity of the Collection, and other important information describing the Collection. There is one ICR for each Collection. The Coast Guard invites comments on whether this ICR should be granted based on the Collection being necessary for the proper performance of Departmental functions. In particular, the Coast Guard would appreciate comments addressing: (1) The practical utility of the Collection; (2) the accuracy of the estimated burden of the Collection; (3) ways to enhance the quality, utility, and clarity of information subject to the Collection; and (4) ways to minimize the burden of the Collection on respondents, including the use of automated collection techniques or other forms of information technology. These comments will help OIRA determine whether to approve the ICR referred to in this Notice.
We encourage you to respond to this request by submitting comments and related materials. Comments to Coast Guard or OIRA must contain the OMB Control Number of the ICR. They must also contain the docket number of this request, [USCG-2015-0475], and must be received by November 23, 2015.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
OIRA posts its decisions on ICRs online at
This request provides a 30-day comment period required by OIRA. The Coast Guard published the 60-day notice (80 FR 45666, July 31, 2015) required by 44 U.S.C. 3506(c)(2). That Notice elicited no comments. Accordingly, no changes have been made to the Collections.
1.
The Paperwork Reduction Act of 1995; 44 U.S.C. chapter 35, as amended.
Coast Guard, DHS.
Sixty-day notice requesting comments.
In compliance with the Paperwork Reduction Act of 1995, the U.S. Coast Guard intends to submit an Information Collection Request (ICR) to the Office of Management and Budget (OMB), Office of Information and Regulatory Affairs (OIRA), requesting approval of revisions to the following collection of information: 1625-0016, Welding and Hot Works Permits; Posting of Warning Signs. Our ICR describe the information we seek to collect from the public. Before submitting this ICR to OIRA, the Coast Guard is inviting comments as described below.
Comments must reach the Coast Guard on or before December 22, 2015.
You may submit comments identified by Coast Guard docket number [USCG-2015-0755] to the Coast Guard using the Federal eRulemaking Portal at
A copy of the ICR is available through the docket on the Internet at
Mr. Anthony Smith, Office of Information Management, telephone 202-475-3532, or fax 202-372-8405, for questions on these documents.
This Notice relies on the authority of the Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended. An ICR is an application to OIRA seeking the approval, extension, or renewal of a Coast Guard collection of information (Collection). The ICR contains information describing the Collection's purpose, the Collection's likely burden on the affected public, an explanation of the necessity of the Collection, and other important information describing the Collection. There is one ICR for each Collection.
The Coast Guard invites comments on whether this ICR should be granted based on the Collection being necessary for the proper performance of Departmental functions. In particular, the Coast Guard would appreciate comments addressing: (1) The practical utility of the Collection; (2) the accuracy of the estimated burden of the Collection; (3) ways to enhance the quality, utility, and clarity of information subject to the Collection; and (4) ways to minimize the burden of the Collection on respondents, including the use of automated collection techniques or other forms of information technology. In response to your comments, we may revise this ICR or decide not to seek approval of revisions of the Collection. We will consider all comments and material received during the comment period.
We encourage you to respond to this request by submitting comments and related materials. Comments must contain the OMB Control Number of the ICR and the docket number of this request, [USCG-2015-0755], and must be received by December 22, 2015.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
1.
The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended.
Coast Guard, DHS.
Thirty-day notice requesting comments.
In compliance with the Paperwork Reduction Act of 1995 the U.S. Coast Guard is forwarding an Information Collection Request (ICR), abstracted below, to the Office of Management and Budget (OMB), Office of Information and Regulatory Affairs (OIRA), requesting approval of a revision to the following collection of information: 1625-0014, Request for Designation and Exemption of Oceanographic Research Vessels. Our ICR describe the information we seek to collect from the public. Review and comments by OIRA ensure we only impose paperwork burdens commensurate with our performance of duties.
Comments must reach the Coast Guard and OIRA on or before November 23, 2015.
You may submit comments identified by Coast Guard docket number [USCG-2015-0634] to the Coast Guard using the Federal eRulemaking Portal at
(1)
(2)
(3)
A copy of the ICR is available through the docket on the Internet at
Contact Mr. Anthony Smith, Office of Information Management, telephone 202-475-3532, or fax 202-372-8405, for questions on these documents.
This Notice relies on the authority of the Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended. An ICR is an application to OIRA seeking the approval, extension, or renewal of a Coast Guard collection of information (Collection). The ICR contains information describing the Collection's purpose, the Collection's likely burden on the affected public, an explanation of the necessity of the Collection, and other important information describing the Collection. There is one ICR for each Collection. The Coast Guard invites comments on whether this ICR should be granted based on the Collection being necessary for the proper performance of Departmental functions. In particular, the Coast Guard would appreciate comments addressing: (1) The practical utility of the Collection; (2) the accuracy of the estimated burden of the Collection; (3) ways to enhance the quality, utility, and clarity of information subject to the Collection; and (4) ways to minimize the burden of the Collection on respondents, including the use of automated collection techniques or other forms of information technology. These comments will help OIRA determine whether to approve the ICR referred to in this Notice.
We encourage you to respond to this request by submitting comments and related materials. Comments to Coast Guard or OIRA must contain the OMB Control Number of the ICR. They must also contain the docket number of this request, [USCG-2015-0634], and must be received by November 23, 2015.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
OIRA posts its decisions on ICRs online at
This request provides a 30-day comment period required by OIRA. The Coast Guard published the 60-day notice (80 FR 45669, July 31, 2015) required by 44 U.S.C. 3506(c)(2). That Notice elicited no comments. Accordingly, no changes have been made to the Collection.
1.
The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended.
Coast Guard, DHS.
Notice of Federal Advisory Committee Meeting.
The National Boating Safety Advisory Council and its
The National Boating Safety Advisory Council will meet Thursday, November 12, 2015, from 12:00 p.m. to 3:30 p.m. and Friday, November 13, 2015 from 1:30 p.m. to 4 p.m. The Boats and Associated Equipment Subcommittee will meet on November 12, 2015, from 3:30 p.m. to 5:15 p.m. The Prevention through People Subcommittee will meet on November 12, 2015, from 5:15 p.m. to 5:45 p.m. on November 12, 2015, and from 8:05 a.m. to 9:05 a.m. on November 13, 2015. The Recreational Boating Safety Strategic Planning Subcommittee will meet on November 13, 2015, from 9:05 a.m. to 12:00 p.m. Please note that these meetings may conclude early if the National Boating Safety Advisory Council has completed all business.
All meetings will be held in the Ballroom of the Holiday Inn Arlington (
For information on facilities or services for individuals with disabilities or to request special assistance at the meeting, contact Mr. Jeff Ludwig, Alternate Designated Federal Officer, telephone 202-372-1061, or at
To facilitate public participation, we are inviting public comment on the issues to be considered by the Council as listed in the “Agenda” section below. Written comments for distribution to Council members must be submitted no later than November 2, 2015, if Council review is desired prior to the meeting. Written comments may be submitted using the Federal eRulemaking Portal at
Docket: For access to the docket to read documents or comments related to this notice, go to
Mr. Jeff Ludwig, Alternate Designated Federal Officer for the National Boating Safety Advisory Council, telephone (202) 372-1061, or at
Notice of this meeting is given under the
The agenda for the National Boating Safety Advisory Council meeting is as follows:
(1) Opening remarks and presentation of awards to outgoing members.
(2) Receipt and discussion of the following reports:
(a) Chief, Office of Auxiliary and Boating Safety, Update on the Coast Guard's implementation of National Boating Safety Advisory Council Resolutions and Recreational Boating Safety Program report.
(b) Alternate Designated Federal Officer's report concerning Council administrative and logistical matters.
(c) Coast Guard Adoption of Electronic Aids to Navigation.
(d) Nonprofit Organization Grant Update.
(e) Progress Report on the Next National Recreational Boating Survey.
(3) Subcommittee Session: Boats and Associated Equipment Subcommittee
(4) Prevention Through People Subcommittee.
(5) Public comment period.
(6) Adjournment of Meeting.
(1) Recreational Boating Safety Strategic Planning Subcommittee.
(1) Receipt and Discussion of the Boats and Associated Equipment, Prevention through People and The Recreational Boating Safety Strategic Planning Subcommittee reports.
(2) Discussion of any recommendations to be made to the Coast Guard.
(3) Public comment period.
(4) Voting on any recommendations to be made to the Coast Guard.
(5) Adjournment of meeting.
There will be a comment period for the National Boating Safety Advisory Council members and a comment period for the public after each report presentation, but before each is voted on by the Council. The Council members will review the information presented on each issue, deliberate on any recommendations presented in the Subcommittees' reports, and formulate recommendations for the Department's consideration.
The meeting agenda and all meeting documentation can be found at:
Public oral comment periods will be held during the meetings after each presentation and at the end of each day. Speakers are requested to limit their comments to 3 minutes. Please note that the public comment periods may end before the time indicated, following the last call for comments. Contact Mr. Jeff Ludwig as indicated above to register as a speaker.
Coast Guard, DHS.
Sixty-day notice requesting comments.
In compliance with the Paperwork Reduction Act of 1995, the U.S. Coast Guard intends to submit an Information Collection Request (ICR) to the Office of Management and Budget (OMB), Office of Information and Regulatory Affairs (OIRA), requesting approval for reinstatement, with change, of the following collection of information: 1625-0112, Enhanced Maritime Domain Awareness via Electronic Transmission of Vessel Transit Data. Our ICR describe the information we seek to collect from the public. Before submitting this ICR to OIRA, the Coast Guard is inviting comments as described below.
Comments must reach the Coast Guard on or before December 22, 2015.
You may submit comments identified by Coast Guard docket number [USCG-2015-0911] to the Coast Guard using the Federal eRulemaking Portal at
A copy of the ICR is available through the docket on the Internet at
Mr. Anthony Smith, Office of Information Management, telephone 202-475-3532, or fax 202-273-8405, for questions on these documents.
This Notice relies on the authority of the Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended. An ICR is an application to OIRA seeking the approval, extension, or renewal of a Coast Guard collection of information (Collection). The ICR contains information describing the Collection's purpose, the Collection's likely burden on the affected public, an explanation of the necessity of the Collection, and other important information describing the Collection. There is one ICR for each Collection.
The Coast Guard invites comments on whether this ICR should be granted based on the Collection being necessary for the proper performance of Departmental functions. In particular, the Coast Guard would appreciate comments addressing: (1) The practical utility of the Collection; (2) the accuracy of the estimated burden of the Collection; (3) ways to enhance the quality, utility, and clarity of information subject to the Collection; and (4) ways to minimize the burden of the Collection on respondents, including the use of automated collection techniques or other forms of information technology. In response to your comments, we may revise this ICR or decide not to seek reinstatement of the Collection. We will consider all comments and material received during the comment period.
We encourage you to respond to this request by submitting comments and related materials. Comments must contain the OMB Control Number of the ICR and the docket number of this request, [USCG-2015-0911], and must be received by December 22, 2015.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
1.
The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended.
Office of the Chief Information Officer, HUD.
Notice.
HUD has submitted the proposed information collection requirement described below to the Office of Management and Budget (OMB) for review, in accordance with the Paperwork Reduction Act. The purpose of this notice is to allow for an additional 30 days of public comment.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB
Colette Pollard, Reports Management Officer, QMAC, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410; email Colette Pollard at
Copies of available documents submitted to OMB may be obtained from Ms. Pollard.
This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.
The
The CoC Homeless Assistance Grant Application (OMB 2506-0112) is the second phase of the information collection process to be used in HUD's CoC Program Competition authorized by the HEARTH Act. During this phase, HUD collects information from the state and local Continuum of Cares (CoCs) through the CoC Consolidated Application which is comprised of the CoC Application, and the Priority Listing which includes the individual project recipients' project applications.
The CoC Consolidated Grant Application is necessary for the selection of proposals submitted to HUD (by State and local governments, public housing authorities, and nonprofit organization) for the grant funds available through the Continuum of Care Program, in order to make decisions for the awarding CoC Program funds.
This notice is soliciting comments from members of the public and affected parties concerning the collection of information described in Section A on the following:
(1) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) The accuracy of the agency's estimate of the burden of the proposed collection of information;
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) Ways to minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
HUD encourages interested parties to submit comment in response to these questions.
12 U.S.C. 1701z-1 Research and Demonstrations.
Office of the Chief Information Officer, HUD.
Notice.
HUD has submitted the proposed information collection requirement described below to the Office of Management and Budget (OMB) for review, in accordance with the Paperwork Reduction Act. The purpose of this notice is to allow for an additional 30 days of public comment.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB Control Number and should be sent to: HUD Desk Officer, Office of Management and Budget, New Executive Office Building, Washington, DC 20503; fax: 202-395-5806. Email:
Colette Pollard, Reports Management Officer, QMAC, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410; email Colette Pollard at
Copies of available documents submitted to OMB may be obtained from Ms. Pollard.
This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.
The
This notice is soliciting comments from members of the public and affected parties concerning the collection of information described in Section A on the following:
(1) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) The accuracy of the agency's estimate of the burden of the proposed collection of information;
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) Ways to minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
HUD encourages interested parties to submit comment in response to these questions.
12 U.S.C. 1701z-1 Research and Demonstrations.
Office of the Assistant Secretary for Community Planning and Development, HUD.
Notice.
This Notice identifies unutilized, underutilized, excess, and surplus Federal property reviewed by HUD for suitability for use to assist the homeless.
Juanita Perry, Department of Housing and Urban Development, 451 Seventh Street SW., Room 7266, Washington, DC 20410; telephone (202) 402-3970; TTY number for the hearing- and speech-impaired (202) 708-2565 (these telephone numbers are not toll-free), or call the toll-free Title V information line at 800-927-7588.
In accordance with 24 CFR part 581 and section 501 of the Stewart B. McKinney Homeless Assistance Act (42 U.S.C. 11411), as amended, HUD is publishing this Notice to identify Federal buildings and other real property that HUD has reviewed for suitability for use to assist the homeless. The properties were reviewed using information provided to HUD by Federal landholding agencies regarding unutilized and underutilized buildings and real property controlled by such agencies or by GSA regarding its inventory of excess or surplus Federal property. This Notice is also published in order to comply with the December 12, 1988 Court Order in
Properties reviewed are listed in this Notice according to the following categories: Suitable/available, suitable/unavailable, and suitable/to be excess, and unsuitable. The properties listed in the three suitable categories have been reviewed by the landholding agencies, and each agency has transmitted to HUD: (1) Its intention to make the property available for use to assist the homeless, (2) its intention to declare the property excess to the agency's needs, or (3) a statement of the reasons that the property cannot be declared excess or made available for use as facilities to assist the homeless.
Properties listed as suitable/available will be available exclusively for homeless use for a period of 60 days from the date of this Notice. Where property is described as for “off-site use only” recipients of the property will be required to relocate the building to their own site at their own expense. Homeless assistance providers interested in any such property should send a written expression of interest to HHS, addressed to: Ms. Theresa M. Ritta, Chief Real Property Branch, the Department of Health and Human Services, Room 5B-17, Parklawn Building, 5600 Fishers Lane, Rockville, MD 20857, (301)-443-2265 (This is not a toll-free number.) HHS will mail to the interested provider an application packet, which will include instructions for completing the application. In order to maximize the opportunity to utilize a suitable property, providers should submit their written expressions of interest as soon as possible. For complete details concerning the processing of applications, the reader is encouraged to refer to the interim rule governing this program, 24 CFR part 581.
For properties listed as suitable/to be excess, that property may, if subsequently accepted as excess by GSA, be made available for use by the homeless in accordance with applicable law, subject to screening for other Federal use. At the appropriate time, HUD will publish the property in a Notice showing it as either suitable/available or suitable/unavailable.
For properties listed as suitable/unavailable, the landholding agency has decided that the property cannot be declared excess or made available for use to assist the homeless, and the property will not be available.
Properties listed as unsuitable will not be made available for any other purpose for 20 days from the date of this Notice. Homeless assistance providers interested in a review by HUD of the determination of unsuitability should call the toll free information line at 1-800-927-7588 for detailed instructions or write a letter to Ann Marie Oliva at the address listed at the beginning of this Notice. Included in the request for review should be the property address (including zip code), the date of publication in the
For more information regarding particular properties identified in this Notice (
Fish and Wildlife Service, Interior.
Notice of issuance of permits.
We, the U.S. Fish and Wildlife Service (Service), have issued the following permits to conduct certain activities with endangered species, marine mammals, or both. We issue these permits under the Endangered Species Act (ESA) and Marine Mammal Protection Act (MMPA).
Brenda Tapia, U.S. Fish and Wildlife Service, Division of Management Authority, Branch of Permits, MS: IA, 5275 Leesburg Pike, Falls Church, VA 22041; fax (703) 358-2281; or email
Brenda Tapia, (703) 358-2104 (telephone); (703) 358-2281 (fax);
On the dates below, as authorized by the provisions of the ESA (16 U.S.C. 1531
Documents and other information submitted with these applications are available for review, subject to the requirements of the Privacy Act and Freedom of Information Act, by any party who submits a written request for a copy of such documents to: U.S. Fish and Wildlife Service, Division of Management Authority, Branch of Permits, MS: IA, 5275 Leesburg Pike, Falls Church, VA 22041; fax (703) 358-2281.
Fish and Wildlife Service, Interior.
Notice of receipt of applications for permit.
We, the U.S. Fish and Wildlife Service, invite the public to comment on the following applications to conduct certain activities with endangered species. With some exceptions, the Endangered Species Act (ESA) prohibits activities with listed species unless Federal authorization is acquired that allows such activities.
We must receive comments or requests for documents on or before November 23, 2015.
•
•
Brenda Tapia, (703) 358-2104 (telephone); (703) 358-2281 (fax);
Send your request for copies of applications or comments and materials concerning any of the applications to the contact listed under
Please make your requests or comments as specific as possible. Please confine your comments to issues for which we seek comments in this notice, and explain the basis for your comments. Include sufficient information with your comments to allow us to authenticate any scientific or commercial data you include.
The comments and recommendations that will be most useful and likely to
Comments, including names and street addresses of respondents, will be available for public review at the street address listed under
To help us carry out our conservation responsibilities for affected species, and in consideration of section 10(a)(1)(A) of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
The applicant requests a permit to import hair samples from wild orangutans (
The applicant requests a permit to import one male and three female captive-bred cheetahs (
The applicant requests a permit to import a sport-hunted trophy of one male bontebok (
Bureau of Indian Affairs, Interior.
Notice of extension of Tribal-State Class III Gaming Compact.
This publishes notice of the extension of the Class III gaming compact between the Pyramid Lake Paiute Tribe and the State of Nevada.
Ms. Paula L. Hart, Director, Office of Indian Gaming, Office of the Deputy Assistant Secretary—Policy and Economic Development, Washington, DC 20240, (202) 219-4066.
Pursuant to 25 CFR 293.5, an extension to an existing tribal-state Class III gaming compact does not require approval by the Secretary if the extension does not include any amendment to the terms of the compact. The Pyramid Lake Paiute Tribe and the State of Nevada have reached an agreement to extend the expiration of their existing Tribal-State Class III gaming compact to February 23, 2017. This publishes notice of the new expiration date of the compact.
Bureau of Indian Affairs, Interior.
Notice of Tribal-State Class III Gaming Compacts taking effect.
The Bureau of Indian Affairs provides notice that the Tribal State Compact between the State of California and the Jackson Band of Miwuk Indians governing Class III gaming (Compact) is effective on publication of this notice.
Ms. Paula L. Hart, Director, Office of Indian Gaming, Office of the Deputy Assistant Secretary—Policy and Economic Development, Washington, DC 20240, (202) 219-4066.
Under section 11 of the Indian Gaming Regulatory Act (IGRA) Public Law 100-497, 25 U.S.C. 2701
Bureau of Indian Affairs, Interior.
Notice of Tribal-State Class III Gaming Compact taking effect.
Notice is hereby given that the Indian Gaming Compact between the State of New Mexico and the Pueblo of Laguna governing Class III gaming (Compact) is taking effect.
Ms. Paula L. Hart, Director, Office of Indian Gaming, Office of the Assistant Secretary—Indian Affairs, Washington, DC 20240, (202) 219-4066.
Under section 11 of the Indian Gaming Regulatory Act (IGRA) Public Law 100-497, 25 U.S.C. 2701
Bureau of Indian Affairs, Interior.
Notice of Tribal-State Class III Gaming Compact taking effect.
Notice is hereby given that the Indian Gaming Compact between the State of New Mexico and the Pueblo of Tesuque governing Class III gaming (Compact) taking effect.
Ms. Paula L. Hart, Director, Office of Indian Gaming, Office of the Assistant Secretary—Indian Affairs, Washington, DC 20240, (202) 219-4066.
Under section 11 of the Indian Gaming Regulatory Act (IGRA) Public Law 100-497, 25 U.S.C. 2701
Bureau of Indian Affairs, Interior.
Notice of Tribal-State Class III Gaming Compacts taking effect.
Notice is hereby given that the Indian Gaming Compact between the State of New Mexico and the Pueblo of Santa Clara governing Class III gaming (Compact) is taking effect.
Ms. Paula L. Hart, Director, Office of Indian Gaming, Office of the Assistant Secretary—Indian Affairs, Washington, DC 20240, (202) 219-4066.
Under section 11 of the Indian Gaming Regulatory Act (IGRA) Public Law 100-497, 25 U.S.C. 2701
Office of Natural Resources Revenue, Interior.
Notice.
The Department of the Interior (Interior) is seeking nominations for individuals to be Committee members or alternates on the U.S. Extractive Industries Transparency Initiative Advisory Committee (Committee). We seek nominees who can represent stakeholder constituencies from government, civil society, and industry so that we can fill current vacancies and create a roster of candidates in case future vacancies occur.
Submit nominations by December 31, 2015.
You may submit nominations by any of the following methods:
• Mail or hand-carry nominations to Ms. Rosita Compton Christian; Department of the Interior, 1849 C Street NW., MS 4211, Washington, DC 20240.
• Email nominations to
Rosita Compton Christian at (202) 208-0272 or (202) 513-0597; fax (202) 513-0682; email
Interior established the Committee on July 26, 2012, in accordance with the provisions of the Federal Advisory Committee Act (FACA), as amended (5 U.S.C. App.2), and with the concurrence of the General Services Administration. The Committee serves as the U.S. Extractive Industries Transparency Initiative Multi-Stakeholder Group and advises the Secretary of the Interior on design and implementation of the initiative.
The Committee does the following:
The Committee consists of representatives from three stakeholder sectors. The sectors are as follows:
In addition to honoring the EITI principle of self-selection within the stakeholder sector, we will consider the following criteria when making final selections:
Nominations should include a resume providing relevant contact information and an adequate description of the nominee's qualifications, including information that would enable the Department of the Interior to make an informed decision regarding meeting the membership requirements for the Committee and to permit the Department of the Interior to contact a potential member.
Parties are strongly encouraged to work with and within stakeholder sectors (including industry, civil society, and government sectors, as the EITI process defines) to jointly consider and submit nominations that, overall, reflect the diversity and breadth of their sector. Nominees are strongly encouraged to include supporting letters from constituents, trade associations, alliances, and/or other organizations that indicate support by a meaningful constituency for the nominee.
Individuals who are Federally registered lobbyists are ineligible to serve on FACA and non-FACA boards, committees, or councils in an individual capacity. The term “individual capacity” refers to individuals who are appointed to exercise their own individual best judgment on behalf of the government, such as when they are designated Special Government Employees, rather than being appointed to represent a particular interest.
The Committee will meet quarterly or at the request of the Designated Federal Officer. Non-Federal members of the Committee will serve without compensation. However, we may pay the travel and per diem expenses of Committee members, if appropriate, under the Federal Travel Regulations.
To learn more about USEITI please visit the official Web site at
Bureau of Land Management, Interior.
Notice of public meeting.
In accordance with the Federal Land Policy and Management Act and the Federal Advisory Committee Act of 1972, and the U.S. Department of the Interior, Bureau of Land Management (BLM), the Eastern Washington Resource Advisory Council (RAC) will meet as indicated below:
The Eastern Washington RAC will hold a public meeting Thursday, Nov. 5, 2015. The meeting will run from 9:00 a.m. to 4:30 p.m. The meeting will be held at the Holiday Inn in Yakima, Washington, and will include a field trip to the Yakima River Canyon. A public comment period will be available in the afternoon.
Jeff Clark, Public Affairs Specialist, BLM Spokane District Office, 1103 N. Fancher Rd., Spokane, Washington 99212, (509) 536-1297, or email
The Eastern Washington RAC consists of 15 members chartered and appointed by the Secretary of the Interior. Their diverse perspectives are represented in commodity, conservation, and general interests. They provide advice to BLM resource managers regarding management plans and proposed resource actions on public land in central and eastern Washington.
Agenda items for the November 2015 meeting include a field tour of the Yakima River Canyon Recreation Area, an update on the Eastern Washington Resource Management Plan, a presentation of the business plan for a fee season extension for the Yakima River Canyon, committee and member updates, and any other matters that may reasonably come before the RAC. This meeting is open to the public in its entirety; however, transportation during the field tour portion of the meeting on Nov. 5 will not be provided to members of the public. Information to be distributed to the Eastern Washington RAC is requested prior to the start of each meeting. A public comment period will be available on Nov. 5, 2015, at 3:30 p.m. Unless otherwise approved by the Eastern Washington RAC Chair, the public comment period will last no longer than 30 minutes. Each speaker may address the RAC for a maximum of 5 minutes. Meeting times and the duration scheduled for public comment periods may be extended or altered when the authorized representative considers it necessary to accommodate business and all who seek to be heard regarding matters before the Eastern Washington RAC.
Bureau of Land Management, Interior.
Notice of public meeting.
In accordance with the Federal Land Policy and Management Act and the Federal Advisory Committee Act of 1972, the U.S. Department of the Interior, Bureau of Land Management (BLM) Northwest Resource Advisory Council (RAC) Travel Management Sub-Group will meet as indicated below.
The Northwest RAC Travel Management Sub-Group has scheduled a meeting November 16, 2015, from 1 to 3 p.m., with a public comment period regarding matters on the agenda at 2 p.m. A specific agenda for the meeting will be available prior to the meeting at
The meeting will be held at the BLM White River Field Office, 220 E. Market St., Meeker, CO 81641.
Heather Sauls, Planning and Environmental Coordinator, White River Field Office, see address above. Phone: (970) 878-3855. Email:
The 15-member Northwest RAC advises the Secretary of the Interior, through the BLM, on a variety of planning and management issues associated with public land management in northwest Colorado. The Northwest RAC has formed a 13-member Travel Management Sub-Group to assist with the BLM Colorado White River Field Office's Travel and Transportation Management Resource Management Plan Amendment. The sub-group provides recommendations to the Northwest RAC but does not directly advise the BLM. This meeting is open to the public. At this meeting, the sub-group will discuss: introductions of new members; an overview of the travel management planning process within the White River Field Office; and the roles and responsibilities of the sub-group, the RAC and the BLM during this planning effort. The public is able to make oral comments to the sub-group at 2 p.m. or submit written comments for the sub-group's consideration. Summary minutes for the Northwest RAC Travel Management Sub-Group meetings will be maintained in the White River Field Office and will be available for public inspection and reproduction during regular business hours for 30 days following the meeting.
National Park Service, Interior.
Notice of availability.
Pursuant to the National Environmental Policy Act of 1969, 42 U.S.C. 4332(2)(C), the National Park Service (NPS) announces the availability of the Draft Environmental Impact Statement (DEIS) for the Nonfederal Oil and Gas Regulations (36 CFR part 9, subpart B) Revisions.
The NPS will accept comments on the DEIS from the public for a period of 60 days following publication by the Environmental Protection Agency (EPA) of the Notice of Availability of the Draft Environmental Impact Statement in the
Copies of the DEIS will be available for public review at
David Steensen, Chief, Geologic Resource Division, National Park Service, P.O. Box 25287, Denver, CO 80225; phone 303.969.2014.
The DEIS evaluates the impacts of three alternatives, including the following alternative elements:
• Elimination of two regulatory provisions that exempt 60% of the oil and gas operations in NPS units. All operators in NPS units would be required to comply with the 9B regulations.
• Elimination of the financial assurance (bonding) cap. Financial assurance would be equal to the reasonable estimated cost of site reclamation.
• Improving enforcement authority by incorporating existing NPS penalty provisions. Law enforcement staff would have authority to write citations for noncompliance with the regulations.
• Authorizing compensation to the federal government for new access on federal lands outside the boundary of an operator's mineral right.
• Reformatting the regulations to make it easier to identify an operator's information requirements and operating standards that apply to each type of operation.
If you wish to comment electronically, you may submit your comments online at the PEPC Web site by visiting
The responsible official for this DEIS is the Associate Director, Natural Resources, Stewardship and Science, 1849 C Street NW., Washington, DC 20240.
This document was received for publication by the Office of the Federal Register on October 20, 2015.
Bureau of Alcohol, Tobacco, Firearms, and Explosives (ATF); Department of Justice.
Notice of list of explosive materials.
Pursuant to 18 U.S.C. 841(d) and 27 CFR 555.23, the Department must publish and revise at least annually in the
The list becomes effective October 23, 2015.
William E. Frye Jr., Chief, Explosives Industry Programs Branch; Firearms and Explosives Industry Division; Bureau of Alcohol, Tobacco, Firearms, and Explosives; United States Department of Justice; 99 New York Avenue NE., Washington, DC 20226; 202 648-7120.
The list includes all mixtures containing any of the materials on the list. Materials constituting blasting agents are marked by an asterisk. While the list is comprehensive, it is not all-inclusive. The fact that an explosive material is not on the list does not mean that it is not within the coverage of the law if it otherwise meets the statutory definitions in 18 U.S.C. 841. Explosive materials are listed alphabetically by their common names followed, where applicable, by chemical names and synonyms in brackets.
The Department has not added any new terms to the list of explosive materials or removed or revised any listing since its last publication. This list supersedes the List of Explosive Materials dated October 7, 2014 (Docket No. 2014R-25T, 79 FR 60496).
Pursuant to 18 U.S.C. 841(d) and 27 CFR 555.23, I hereby designate the following as explosive materials covered under 18 U.S.C. 841(c):
Acetylides of heavy metals.
Aluminum containing polymeric propellant.
Aluminum ophorite explosive.
Amatex.
Amatol.
Ammonal.
Ammonium nitrate explosive mixtures (cap sensitive).
* Ammonium nitrate explosive mixtures (non-cap sensitive).
Ammonium perchlorate having particle size less than 15 microns.
Ammonium perchlorate explosive mixtures (excluding ammonium perchlorate composite propellant (APCP)).
Ammonium picrate [picrate of ammonia, Explosive D].
Ammonium salt lattice with isomorphously substituted inorganic salts.
* ANFO [ammonium nitrate-fuel oil].
Aromatic nitro-compound explosive mixtures.
Azide explosives.
Baranol.
Baratol.
BEAF [1, 2-bis (2, 2-difluoro-2-nitroacetoxyethane)].
Black powder.
Black powder based explosive mixtures.
Black powder substitutes.
*Blasting agents, nitro-carbo-nitrates, including non-cap sensitive slurry and water gel explosives.
Blasting caps.
Blasting gelatin.
Blasting powder.
BTNEC [bis (trinitroethyl) carbonate].
BTNEN [bis (trinitroethyl) nitramine].
BTTN [1,2,4 butanetriol trinitrate].
Bulk salutes.
Butyl tetryl.
Calcium nitrate explosive mixture.
Cellulose hexanitrate explosive mixture.
Chlorate explosive mixtures.
Composition A and variations.
Composition B and variations.
Composition C and variations.
Copper acetylide.
Cyanuric triazide.
Cyclonite [RDX].
Cyclotetramethylenetetranitramine [HMX].
Cyclotol.
Cyclotrimethylenetrinitramine [RDX].
DATB [diaminotrinitrobenzene].
DDNP [diazodinitrophenol].
DEGDN [diethyleneglycol dinitrate].
Detonating cord.
Detonators.
Dimethylol dimethyl methane dinitrate composition.
Dinitroethyleneurea.
Dinitroglycerine [glycerol dinitrate].
Dinitrophenol.
Dinitrophenolates.
Dinitrophenyl hydrazine.
Dinitroresorcinol.
Dinitrotoluene-sodium nitrate explosive mixtures.
DIPAM [dipicramide; diaminohexanitrobiphenyl].
Dipicryl sulfone.
Dipicrylamine.
Display fireworks.
DNPA [2,2-dinitropropyl acrylate].
DNPD [dinitropentano nitrile].
Dynamite.
EDDN [ethylene diamine dinitrate].
EDNA [ethylenedinitramine].
Ednatol.
EDNP [ethyl 4,4-dinitropentanoate].
EGDN [ethylene glycol dinitrate].
Erythritol tetranitrate explosives.
Esters of nitro-substituted alcohols.
Ethyl-tetryl.
Explosive conitrates.
Explosive gelatins.
Explosive liquids.
Explosive mixtures containing oxygen-releasing inorganic salts and hydrocarbons.
Explosive mixtures containing oxygen-releasing inorganic salts and nitro bodies.
Explosive mixtures containing oxygen-releasing inorganic salts and water insoluble fuels.
Explosive mixtures containing oxygen-releasing inorganic salts and water soluble fuels.
Explosive mixtures containing sensitized nitromethane.
Explosive mixtures containing tetranitromethane (nitroform).
Explosive nitro compounds of aromatic hydrocarbons.
Explosive organic nitrate mixtures.
Explosive powders.
Flash powder.
Fulminate of mercury.
Fulminate of silver.
Fulminating gold.
Fulminating mercury.
Fulminating platinum.
Fulminating silver.
Gelatinized nitrocellulose.
Gem-dinitro aliphatic explosive mixtures.
Guanyl nitrosamino guanyl tetrazene.
Guanyl nitrosamino guanylidene hydrazine.
Guncotton.
Heavy metal azides.
Hexanite.
Hexanitrodiphenylamine.
Hexanitrostilbene.
Hexogen [RDX].
Hexogene or octogene and a nitrated N-methylaniline.
Hexolites.
HMTD [hexamethylenetriperoxidediamine].
HMX [cyclo-1,3,5,7-tetramethylene 2,4,6,8-tetranitramine; Octogen].
Hydrazinium nitrate/hydrazine/aluminum explosive system.
Hydrazoic acid.
Igniter cord.
Igniters.
Initiating tube systems.
KDNBF [potassium dinitrobenzo-furoxane].
Lead azide.
Lead mannite.
Lead mononitroresorcinate.
Lead picrate.
Lead salts, explosive.
Lead styphnate [styphnate of lead, lead trinitroresorcinate].
Liquid nitrated polyol and trimethylolethane.
Liquid oxygen explosives.
Magnesium ophorite explosives.
Mannitol hexanitrate.
MDNP [methyl 4,4-dinitropentanoate].
MEAN [monoethanolamine nitrate].
Mercuric fulminate.
Mercury oxalate.
Mercury tartrate.
Metriol trinitrate.
Minol-2 [40% TNT, 40% ammonium nitrate, 20% aluminum].
MMAN [monomethylamine nitrate]; methylamine nitrate.
Mononitrotoluene-nitroglycerin mixture.
Monopropellants.
NIBTN [nitroisobutametriol trinitrate].
Nitrate explosive mixtures.
Nitrate sensitized with gelled nitroparaffin.
Nitrated carbohydrate explosive.
Nitrated glucoside explosive.
Nitrated polyhydric alcohol explosives.
Nitric acid and a nitro aromatic compound explosive.
Nitric acid and carboxylic fuel explosive.
Nitric acid explosive mixtures.
Nitro aromatic explosive mixtures.
Nitro compounds of furane explosive mixtures.
Nitrocellulose explosive.
Nitroderivative of urea explosive mixture.
Nitrogelatin explosive.
Nitrogen trichloride.
Nitrogen tri-iodide.
Nitroglycerine [NG, RNG, nitro, glyceryl trinitrate, trinitroglycerine].
Nitroglycide.
Nitroglycol [ethylene glycol dinitrate, EGDN].
Nitroguanidine explosives.
Nitronium perchlorate propellant mixtures.
Nitroparaffins Explosive Grade and ammonium nitrate mixtures.
Nitrostarch.
Nitro-substituted carboxylic acids.
Nitrourea.
Octogen [HMX].
Octol [75 percent HMX, 25 percent TNT].
Organic amine nitrates.
Organic nitramines.
PBX [plastic bonded explosives].
Pellet powder.
Penthrinite composition.
Pentolite.
Perchlorate explosive mixtures.
Peroxide based explosive mixtures.
PETN [nitropentaerythrite, pentaerythrite tetranitrate, pentaerythritol tetranitrate].
Picramic acid and its salts.
Picramide.
Picrate explosives.
Picrate of potassium explosive mixtures.
Picratol.
Picric acid (manufactured as an explosive).
Picryl chloride.
Picryl fluoride.
PLX [95% nitromethane, 5% ethylenediamine].
Polynitro aliphatic compounds.
Polyolpolynitrate-nitrocellulose explosive gels.
Potassium chlorate and lead sulfocyanate explosive.
Potassium nitrate explosive mixtures.
Potassium nitroaminotetrazole.
Pyrotechnic compositions.
Pyrotechnic fuses.
PYX [2,6-bis(picrylamino)] 3,5-dinitropyridine.
RDX [cyclonite, hexogen, T4, cyclo-1,3,5,-trimethylene-2,4,6,-trinitramine; hexahydro-1,3,5-trinitro-S-triazine].
Safety fuse.
Salts of organic amino sulfonic acid explosive mixture.
Salutes (bulk).
Silver acetylide.
Silver azide.
Silver fulminate.
Silver oxalate explosive mixtures.
Silver styphnate.
Silver tartrate explosive mixtures.
Silver tetrazene.
Slurried explosive mixtures of water, inorganic oxidizing salt, gelling agent, fuel, and sensitizer (cap sensitive).
Smokeless powder.
Sodatol.
Sodium amatol.
Sodium azide explosive mixture.
Sodium dinitro-ortho-cresolate.
Sodium nitrate explosive mixtures.
Sodium nitrate-potassium nitrate explosive mixture.
Sodium picramate.
Special fireworks.
Squibs.
Styphnic acid explosives.
Tacot [tetranitro-2,3,5,6-dibenzo-1,3a,4,6a tetrazapentalene].
TATB [triaminotrinitrobenzene].
TATP [triacetonetriperoxide].
TEGDN [triethylene glycol dinitrate].
Tetranitrocarbazole.
Tetrazene [tetracene, tetrazine, 1(5-tetrazolyl)-4-guanyl tetrazene hydrate].
Tetrazole explosives.
Tetryl [2,4,6 tetranitro-N-methylaniline].
Tetrytol.
Thickened inorganic oxidizer salt slurried explosive mixture.
TMETN [trimethylolethane trinitrate].
TNEF [trinitroethyl formal].
TNEOC [trinitroethylorthocarbonate].
TNEOF [trinitroethylorthoformate].
TNT [trinitrotoluene, trotyl, trilite, triton].
Torpex.
Tridite.
Trimethylol ethyl methane trinitrate composition.
Trimethylolthane trinitrate-nitrocellulose.
Trimonite.
Trinitroanisole.
Trinitrobenzene.
Trinitrobenzoic acid.
Trinitrocresol.
Trinitro-meta-cresol.
Trinitronaphthalene.
Trinitrophenetol.
Trinitrophloroglucinol.
Trinitroresorcinol.
Tritonal.
Urea nitrate.
Water-bearing explosives having salts of oxidizing acids and nitrogen bases, sulfates, or sulfamates (cap sensitive).
Water-in-oil emulsion explosive compositions.
Xanthamonas hydrophilic colloid explosive mixture.
Notice is hereby given that, on September 22, 2015, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and PERF intends to file additional written notifications disclosing all changes in membership.
On February 10, 1986, PERF filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on December 9, 2014. A notice was published in the
Notice is hereby given that, on September 22, 2015, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Also, PetroSkills, LLC, Katy, TX, has withdrawn as a party to this venture.
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and STAR intends to file additional written notifications disclosing all changes in membership.
On August 8, 2014, STAR filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on May 15, 2015. A notice was published in the
Notice is hereby given that, on September 24, 2015, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Also, Aframe, London, UNITED KINGDOM; Extreme Reach, Dallas, TX; Marquis Broadcast, Pangbourne, UNITED KINGDOM; Quantel Ltd., Newbury, Berkshire, UNITED KINGDOM; John A. Hoehn (individual member), Pennsville, NJ; and John Warburton (individual member), Montreal, CANADA, have withdrawn as parties to this venture.
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and Advanced Media Workflow Association, Inc. intends to file additional written notifications disclosing all changes in membership.
On March 28, 2000, Advanced Media Workflow Association, Inc. filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on June 19, 2015. A notice was published in the
Notice is hereby given that, on September 22, 2015, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Also, Silvaco, Inc., Santa Clara, CA; Yonsei University, Seoul, REPUBLIC OF KOREA; Inpria Corporation, Corvallis, OR; Shin Etsu Chemical Co., Ltd., Tokyo, JAPAN; Rion Co., Ltd., Tokyo, JAPAN; AIXTRON SE., Herzogenrath, GERMANY; Nova Measuring Instruments, Ltd., Rehovot, ISRAEL; and Conexant Systems, Inc., Irvine, CA, have withdrawn as parties to this venture.
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and SEMATECH intends to file additional written notifications disclosing all changes in membership.
On April 22, 1988, SEMATECH filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on June 23, 2015. A notice was published in the
Notice is hereby given that, on September 23, 2015, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Also, Harman International, Stamford, CT; Local Motors, Chandler, AZ; Octoblu, Inc., Tempe, AZ; Vedams, Inc., San Jose, CA; MachineShop, Inc., Boston, MA; ControlBEAM Digital Automation, Irvine, CA; ISI Technology, Charleston, SC; Tellient, San Diego, CA; Ciseco, Nottingham, UNITED KINGDOM; Discretix Technologies Ltd., Kfar Netter, ISRAEL; and Yifang Digital Technology Co., Ltd., Shenzhen, PEOPLE'S REPUBLIC OF CHINA, have withdrawn as parties to this venture.
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and AllSeen Alliance intends to file additional written notifications disclosing all changes in membership.
On January 29, 2014, AllSeen Alliance filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on July 13, 2015. A notice was published in the
Notice is hereby given that, on September 22, 2015, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and AEF intends to file additional written notifications disclosing all changes in membership.
On March 20, 2015, AEF filed its original notification pursuant to section
The last notification was filed with the Department on May 19, 2015. A notice was published in the
Notice is hereby given that, on September 25, 2015, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Also, Gas Technology Institute, Des Moines, IA; MidAmerican Energy Company, Davenport, IA; Opower, Arlington, VA; Businovation, LLC, Basking Ridge, NJ; and Machine-to-Machine Intelligence Corporation (M2Mi), Moffett Field, CA, have withdrawn as parties to this venture.
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and MSGIP 2.0 intends to file additional written notifications disclosing all changes in membership.
On February 5, 2013, MSGIP 2.0 filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on June 29, 2015. A notice was published in the
Employment and Training Administration (ETA), Labor.
Notice.
The Department of Labor (Department), as part of its continuing effort to reduce paperwork and respondent burden, conducts a preclearance consultation program to provide the public and Federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 [44 U.S.C. 3506(c)(2)(A)]. This program helps ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirements on respondents can be properly assessed.
Currently, ETA is soliciting comments concerning the collection of data for the UI DV program. Collection authority for this program expires May 31, 2016.
Submit written comments to the office listed in the addresses section below on or before December 22, 2015.
Send written comments to Rachel Beistel, Room S-4519, Employment and Training Administration, U.S. Department of Labor, 200 Constitution Avenue NW., Washington, DC 20210. Telephone number: 202-693-2736 (this is not a toll-free number). Individuals with hearing or speech impairments may access the telephone number above via TTY by calling the toll-free Federal Information Relay Service at 1-877-889-5627 (TTY/TDD). Email:
Section 303(a)(6) of the Social Security Act specifies that the Secretary of Labor will not certify State UI programs to receive administrative grants unless the State's law includes provisions for: making of such reports . . . as the Secretary of Labor may from time to time require, and compliance with such provisions as the Secretary may from time to time find necessary to assure the correctness and verification of such reports.
The Department considers data validation one of those “provisions . . . necessary to assure the correctness and verification” of the reports it requires.
The Government Performance and Results Act of 1993 (GPRA) requires Federal agencies to develop annual and strategic performance plans that establish performance goals, have concrete indicators of the extent that goals are achieved, and set performance targets. Each year, the agency is to issue a report that “evaluate[s] the performance plan for the current fiscal year relative to the performance achieved toward the performance goals in the fiscal year covered by the report.” Section 1116 (d)(2) of OMB Circular A-11, which implements the GPRA process, cites the Reports Consolidation Act of 2000 to emphasize the need for data validation by requiring that the agency's annual performance report “contain an assessment of the completeness and reliability of the performance data included in it [that] . . . describes any material inadequacies in the completeness and reliability of the data.” (OMB Circular A-11, Section 230.2 (f)). The Department emphasizes the importance of complete and accurate information for program monitoring and improving program performance.
The UI DV program employs a refined and automated approach to review 322 elements reported on 13 benefits reports and one tax report. The Department uses many of these elements for key performance measures as well as for workload analysis.
The validation process assesses the validity (accuracy) of the counts of transactions or measurements of status as follows. Guided by a detailed handbook, the state first constructs extract files containing all pertinent individual transactions for the desired report period to be validated. These transactions are grouped into 16 benefits
The software also draws samples of most transaction types from the extract files. Guided by a state-specific handbook, the validators review these sample records against documentation in the state's management information system to determine whether the transactions in the extract file are supported by system documentation. This qualitative check determines whether the validation count can be trusted as accurate. The benefits extract files are considered to pass this “quality” review if random samples indicate that no more than 5% of the records contain errors; tax files are subjected to different but related tests. A reported count is considered valid only if it differs from a reconstructed (validation) count by no more than the appropriate criterion of ±2% or ±1%, and the validation count comes from an extract file that has satisfied all quality tests.
For Federal fiscal years 2011 and beyond, all states will be required to conduct a complete validation every three years. In three cases the three-year rule does not apply, and a revalidation must occur within one year: (1) Groups of reported counts that are summed for purposes of making a Pass/Fail determination and do not pass validation by being within ±2% of the reconstructed counts or the extract file does not pass all quality tests; (2) the validation applies to the two benefits populations and one tax population used for GPRA measures; and (3) reports are produced by new reporting software. Every year states must also certify that Module 3 of the Benefits and Tax handbooks are up to date.
In August 2015, through Unemployment Insurance Program Letter 08-12, Change 1, the Department issued changes that increased the high dollar overpayment threshold from $5,000 to $25,000 on the ETA 227 report. The ETA 227 report is validated through four of the 16 benefit populations. Only the validation of Benefits Population 12 will be affected by the new threshold of $25,000. Accommodating the new threshold requires: (1) Changing the threshold amount in the data validation database programming; (2) making one-time changes to two rows of data that validate the 227 report; and (3) adapting the affected Overpayment rules (called Steps or Substeps) to Module 3 of the Benefits handbook, which contains State definitions and data system locations for Federal reporting requirements. These changes will impose little to no additional burden on state validators.
The Department is particularly interested in comments which:
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
We will summarize and/or include in the request for OMB approval of the ICR, the comments received in response to this comment request; they will also become a matter of public record.
Notice.
The Department of Labor (DOL) is submitting the Employee Benefits Security Administration (EBSA) sponsored information collection request (ICR) titled, “Prohibited Transaction Exemption 1990-1, Insurance Company Pooled Separate Accounts,” to the Office of Management and Budget (OMB) for review and approval for continued use, without change, in accordance with the Paperwork Reduction Act of 1995 (PRA), 44 U.S.C. 3501
The OMB will consider all written comments that agency receives on or before November 23, 2015.
A copy of this ICR with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained free of charge from the RegInfo.gov Web site at
Submit comments about this request by mail or courier to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for DOL-EBSA, Office of Management and Budget, Room 10235, 725 17th Street NW., Washington, DC 20503; by Fax: 202-395-5806 (this is not a toll-free number); or by email:
Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or by email at
44 U.S.C. 3507(a)(1)(D).
This ICR seeks to extend PRA authority for the Prohibited Transaction Exemption 1990-1 (PTE 90-1), Insurance Company Pooled Separate Accounts information collection. PTE 90-1 provides an exemption from certain Employee Retirement Income Security Act of 1974 (ERISA) provisions relating to transactions involving insurance company pooled separate accounts in which employee benefit plans participate. Without the exemption, Internal Revenue Code section 4975(c)(1) and ERISA sections 406 and 407(a) might prohibit a party in interest to a plan from furnishing goods or services to an insurance company pooled separate account in which the plan has an interest or prohibit engaging in other transactions.
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.
OMB authorization for an ICR cannot be for more than three (3) years without renewal, and the current approval for this collection is scheduled to expire on October 31, 2015. The DOL seeks to extend PRA authorization for this information collection for three (3) more years, without any change to existing requirements. The DOL notes that existing information collection requirements submitted to the OMB receive a month-to-month extension while they undergo review. For additional substantive information about this ICR, see the related notice published in the
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Notice.
The National Endowment for the Arts (NEA), as part of its continuing effort to reduce paperwork and respondent burden, conducts a preclearance consultation program to provide the general public and Federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) [44 U.S.C. 3506(c)(A)]. This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirements on respondents can be properly assessed. Currently, the NEA is soliciting comments concerning the proposed information collection on arts participation in the U.S. A copy of the current information collection request can be obtained by contacting the office listed below in the address section of this notice.
Written comments must be submitted to the office listed in the address section below within 60 days from the date of this publication in the
• Evaluate whether the proposed collection of information is necessary
• 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,
Send comments to: Sunil Iyengar, National Endowment for the Arts, 400 7th Street SW., Washington, DC 20506-0001, telephone (202) 682-5424 (this is not a toll-free number), fax (202) 682-5677, or send via email to
Nuclear Regulatory Commission.
Notice of submission to the Office of Management and Budget; request for comment.
The U.S. Nuclear Regulatory Commission (NRC) has recently submitted a request for renewal of an existing collection of information to the Office of Management and Budget (OMB) for review. The information collection is entitled, “Exemptions and Continued Regulatory Authority in Agreement States and in Offshore Waters Under Section 274.”
Submit comments by November 23, 2015.
Submit comments directly to the OMB reviewer at: Vlad Dorjets, Desk Officer, Office of Information and Regulatory Affairs (3150-0032), NEOB-10202, Office of Management and Budget, Washington, DC 20503; telephone: 202-395-7315, email:
Tremaine Donnell, NRC Clearance Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-6258; email:
Please refer to Docket ID NRC-2015-0141 when contacting the NRC about the availability of information for this action. You may obtain publicly-available information related to this action by any of the following methods:
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The NRC cautions you not to include identifying or contact information in comment submissions that you do not want to be publicly disclosed in your comment submission. All comment submissions are posted at
If you are requesting or aggregating comments from other persons for submission to the OMB, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that comment submissions are not routinely edited to remove such information before making the comment submissions available to the public or entering the comment into ADAMS.
Under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the NRC recently submitted a request for renewal of an existing collection of information to OMB for review entitled, “Exemptions and Continued Regulatory Authority in Agreement States and in Offshore Waters Under Section 274.” The NRC hereby informs potential respondents that an agency may not conduct or sponsor, and that a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
The NRC published a
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Pension Benefit Guaranty Corporation.
Notice of intent to request OMB approval of modifications to information collection.
The Pension Benefit Guaranty Corporation (“PBGC”) intends to request that the Office of Management and Budget (“OMB”) approve modifications to a collection of information under the Paperwork Reduction Act. The purpose of the information collection is to enable the PBGC to pay benefits to participants and beneficiaries. This notice informs the public of PBGC's intent and solicits public comment on the collection of information, as modified.
Comments should be submitted by December 22, 2015.
Comments may be submitted by any of the following methods:
PBGC will make all comments available on its Web site at
Copies of the collection of information may be obtained without charge by writing to the Disclosure Division of the Office of the General Counsel of PBGC at the above address or by visiting that office or calling 202-326-4040 during normal business hours. (TTY and TDD users may call the Federal relay service toll-free at 1-800-877-8339 and ask to be connected to 202-326-4040.) The regulations relating to this collection of information are available on PBGC's Web site at
Jo Amato Burns, Attorney, Office of the General Counsel, Pension Benefit Guaranty Corporation, 1200 K Street NW., Washington, DC 20005-4026, 202-326-4400. (For TTY and TDD, call 800-877-8339 and ask to be connected to 202-326-4400.)
PBGC intends to request that OMB approve modifications to a collection of information needed to pay participants and beneficiaries who may be entitled to pension benefits under defined benefit plans that have terminated. The collection consists of information participants and beneficiaries are asked to provide in connection with an application for benefits. In addition, in some instances, as part of an effort to identify participants and beneficiaries who may be entitled to benefits, PBGC requests individuals to provide identifying information that the individual would provide as part of an initial contact with PBGC. All requested information is needed to enable PBGC to determine benefit entitlements and to make appropriate payments.
The information collection includes My Pension Benefit Account (My PBA), an application on PBGC's Web site,
PBGC is proposing to add a new form to the information collection: Form XXX, Benefit Inquiry Questionnaire. PBGC will send this form to individuals who contact PBGC to inquire whether PBGC is holding any benefits to which they are entitled. The questionnaire will request information that PBGC needs to determine whether the individual is owed benefits and, if so, the benefit amount.
In addition, PBGC is making clarifying, simplifying, editorial, and other changes to other forms in the information collection.
The existing collection of information under the regulation was approved under OMB control number 1212-0055 (expires December 31, 2015). PBGC intends to request that OMB extend its approval (with modifications) for three years. 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.
PBGC estimates the total annual burden associated with this collection of information will be 73,000 hours and $1,900.
PBGC is soliciting public comments to—
• Evaluate whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the 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 the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Office of Personnel Management.
30-Day notice and request for comments.
The Healthcare & Insurance/Federal Employee Insurance Operations (FEIO), Office of Personnel Management (OPM) offers the general public and other federal agencies the opportunity to comment on a revised information collection request (ICR) 3206-0160, Health Benefits Election Form. As required by the Paperwork Reduction Act of 1995, (Pub. L. 104-13, 44 U.S.C. chapter 35) as amended by the Clinger-Cohen Act (Pub. L. 104-106), OPM is soliciting comments for this collection. The information collection was previously published in the
Comments are encouraged and will be accepted until November 23, 2015. This process is conducted in accordance with 5 CFR 1320.1.
Interested persons are invited to submit written comments on the proposed information collection to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention: Desk Officer for the Office of Personnel Management or sent via electronic mail to
A copy of this ICR, with applicable supporting documentation, may be obtained by contacting the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention: Desk Officer for the Office of Personnel Management or sent via electronic mail to
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,
The Health Benefits Election Form is used by Federal employees, annuitants other than those under the Civil Service Retirement System (CSRS) and the Federal Employees Retirement System (FERS) including individuals receiving benefits from the Office of Workers' Compensation Programs, former spouses eligible for benefits under the Spouse Equity Act of 1984, and separated employees and former dependents eligible to enroll under the Temporary Continuation of Coverage provisions of the FEHB law (5 U.S.C. 8905a). A different form (OPM 2809) is used by CSRS and FERS annuitants whose health benefit enrollments are administered by OPM's Retirement Operations.
Postal Regulatory Commission.
Notice.
The Commission is noticing a recent Postal Service filing concerning the Postal Service's request to remove Global Direct Contracts from the competitive products list. This notice informs the public of the filing, invites public comment, and takes other administrative steps.
Submit comments electronically via the Commission's Filing Online system at
David A. Trissell, General Counsel, at 202-789-6820.
In accordance with 39 U.S.C. 3642 and 39 CFR 3020.30
To support its Request, the Postal Service filed four attachments as follows:
• Attachment A—a redacted copy of the Governors' Decision No. 11-6 authorizing the removal of the product from the competitive product list, including a redacted management analysis;
• Attachment B—an application for nonpublic treatment of Governors' Decision No. 11-6;
• Attachment C—a Statement of Supporting Justification as required by 39 CFR 3020.32; and
• Attachment D—proposed changes to the Mail Classification Schedule (MCS) competitive product list.
The Postal Service seeks to remove Global Direct Contracts from the competitive product list due to the absence of customer demand for this service. Request at 1. The Postal Service asserts that removal of Global Direct Contracts is an attempt to align its service offerings with current customer needs and preferences.
In addition, in the Statement of Supporting Justification, Giselle E. Valera, Vice President and Managing Director of Global Business, asserts that because the Postal Service is requesting product removal, the product's ability to cover its own costs has no impact on the instant Request.
The Commission establishes Docket No. MC2016-7 to consider the Request pertaining to the removal of Global Direct Contracts from the competitive product list.
Interested persons may submit comments on whether the Postal Service's filings in the captioned docket are consistent with the policies of 39 U.S.C. 3632, 3633, or 3642, 39 CFR part 3010, 39 CFR part 3015, and 39 CFR part 3020, subpart B and subpart E. Comments are due no later than October 26, 2015. The public portions of the filings can be accessed via the Commission's Web site (
The Commission appoints James F. Callow to serve as Public Representative in this docket.
1. The Commission establishes Docket No. MC2016-7 to consider the Postal Service's Request.
2. Pursuant to 39 U.S.C. 505, James F. Callow is appointed to serve as an officer of the Commission (Public Representative) to represent the interests of the general public in these proceedings.
3. Comments by interested persons in these proceedings are due no later than October 26, 2015.
4. The Secretary shall arrange for publication of this order in the
Postal Service.
Notice.
The Postal Service hereby provides notice that it has filed a request with the Postal Regulatory Commission to remove Global Direct Contracts from the competitive product list.
Keith Nusbaum, 202-268-6687.
On October 16, 2015, the United States Postal Service® filed with the Postal Regulatory Commission a Request of the United States Postal Service to remove Global Direct Contracts from the Competitive Product List, pursuant to 39 U.S.C. 3642. Documents pertinent to this request are available at
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act” or “SEA”)
FINRA is filing the content outline and selection specifications for the new Securities Trader qualification examination (Series 57).
The Series 57 content outline is attached.
The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
Section 15A(g)(3) of the Act
The Commission recently approved a proposed rule change to amend NASD Rule 1032(f) (Limited Representative—Equity Trader) to replace the Equity Trader registration category and qualification examination (Series 55) with the Securities Trader registration category and qualification examination (Series 57).
In addition, the Commission approved amendments to NASD Rule 1022(a) (General Securities Principal) to establish a Securities Trader Principal registration category and require each associated person of a member who is included within the definition of “principal” in NASD Rule 1021 (Registration Requirements) with supervisory responsibility over the securities trading activities described in NASD Rule 1032(f), to qualify and register as a Securities Trader Principal.
FINRA is expecting the national securities exchanges to file similar proposed rule changes to replace the Proprietary Trader qualification examination (Series 56) with the Series 57 examination in their respective registration rules relating to securities trading activities. Further, the Series 57 examination will replace the Series 56 examination for those exchange registration categories, such as the Proprietary Trader Principal registration category, where the Series 56 examination is currently an acceptable prerequisite.
FINRA developed the Series 57 examination in consultation with a committee of industry representatives and representatives of several exchanges. The examination is based on the current job functions of a Securities Trader and includes elements of the Series 55 and 56 examinations. The Series 57 content outline covers the laws, rules and regulations relevant to securities trading as well as the functions and associated tasks performed by a Securities Trader.
The Series 57 content outline is divided into four major job functions that are performed by a Securities Trader. The following are the four major job functions, denoted Function 1 through 4, with the associated number of questions:
Function 1: Market Overview and Products, 22 questions;
Function 2: Engaging in Professional Conduct and Adhering to Regulatory Requirements, 12 questions;
Function 3: Trading Activities, 79 questions; and
Function 4: Maintaining Books and Records and Trade Reporting, 12 questions.
The number of questions assigned to each major job function reflects the key tasks performed by a Securities Trader.
Each function also includes specific tasks describing activities associated with performing that function. There are three tasks (1.1-1.3) associated with Function 1; two tasks (2.1-2.2) associated with Function 2; three tasks (3.1-3.3) associated with Function 3; and two tasks (4.1-4.2) associated with Function 4.
The content outline also includes sample questions
The number of questions on the Series 57 examination will be 125 scored
The Series 57 content outline is available on FINRA's Web site, at
FINRA is filing the proposed rule change for immediate effectiveness. FINRA proposes to implement the Series 57 examination on January 4, 2016. FINRA will announce the proposed rule change and the implementation date in a
FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The new examination aligns with the functions and associated tasks currently performed by associated persons engaged in securities trading and tests knowledge of the laws, rules, regulations and skills relevant to those functions and associated tasks.
Written comments were neither solicited nor received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Robert W. Errett, Deputy Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act” or “SEA”)
FINRA is filing revisions to the content outline and selection specifications for the Introducing Broker-Dealer Financial and Operations Principal (Series 28) examination program.
The revised content outline is attached.
The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
Section 15A(g)(3) of the Act
NASD Rule 1022(c)(1) requires that every member that is subject to the requirements of SEA Rule 15c3-1,
• Final approval and responsibilities for the accuracy of financial reports submitted to any duly established securities industry regulatory body;
• final preparation of such reports;
• supervision of individuals who assist in the preparation of such reports;
• supervision of and responsibility for individuals who are involved in the actual maintenance of the member's books and records from which such reports are derived;
• supervision and/or performance of the member's responsibilities under all financial responsibility rules promulgated pursuant to the provisions of the Act;
• overall supervision of and responsibility for the individuals who are involved in the administration and maintenance of the member's back office operations; or
• any other matter involving the financial and operational management of the member.
NASD Rule 1022(c)(3) provides that, except as set forth in NASD Rule 1021(c),
NASD Rule 1022(c)(4) provides that a person registered solely as an Introducing Broker-Dealer Financial and Operations Principal shall not be qualified to function in a principal capacity with responsibility over any
In consultation with a committee of industry representatives, FINRA recently undertook a review of the Series 28 examination program. As a result of this review, FINRA is proposing to make revisions to the content outline to reflect changes to the laws, rules and regulations covered by the examination and to incorporate the functions and associated tasks currently performed by an Introducing Broker-Dealer Financial and Operations Principal. FINRA also is proposing to make changes to the format of the content outline.
The current content outline is divided into five sections. The following are the five sections and the number of questions associated with each of the sections, denoted Section 1 through Section 5:
1. Keeping And Preservation of Records and Broker-Dealer Financial Reporting Requirements, 16 questions;
2. Net Capital Requirements, 36 questions;
3. Customer Protection, 10 questions;
4. Uniform Practice Rules, 5 questions; and
5. Other Relevant Regulations and Interpretations, 28 questions.
Each section also includes the applicable laws, rules and regulations associated with that section. The current outline also includes a preface (addressing, among other things, the purpose, administration and scoring of the examination), sample questions and reference materials.
To develop the revised outline, FINRA conducted a job analysis study of Introducing Broker-Dealer Financial and Operations Principals, which included the use of a survey. The study provided detailed information regarding the day-to-day roles, responsibilities and job functions of Introducing Broker-Dealer Financial and Operations Principals. As a result, FINRA is proposing to revise the structure of the outline as described below to include functions and associated tasks that reflect the day-to-day activities of an Introducing Broker-Dealer Financial and Operations Principal.
Specifically, FINRA is proposing to divide the content outline into four major job functions that are performed by an Introducing Broker-Dealer Financial and Operations Principal. The following are the four major job functions, denoted Function 1 through Function 4, with the associated number of questions:
Function 1: Financial Reporting, 16 questions;
Function 2: Operations, General Securities Industry Regulations, and Preservation of Books and Records, 30 questions;
Function 3: Net Capital, 31 questions; and
Function 4: Customer Protection, Funding and Cash Management, 18 questions.
As noted above, each major job function includes an assigned number of questions. FINRA determined the number of questions for each function based on the results of the job analysis study. Thus, compared to the existing outline, the allocation of questions in the revised outline more closely reflects the current day-to-day activities of an Introducing Broker-Dealer Financial and Operations Principal.
Each function also includes specific tasks describing activities associated with performing that function. There are five tasks (1.1-1.5) associated with Function 1; three tasks (2.1-2.3) associated with Function 2; seven tasks (3.1-3.7) associated with Function 3; and three tasks (4.1-4.3) associated with Function 4.
As noted above, FINRA also is proposing to revise the content outline to reflect changes to the laws, rules and regulations covered by the examination. Among other revisions, FINRA is proposing to revise the content outline to reflect the adoption of rules in the consolidated FINRA rulebook (
FINRA is proposing similar changes to the Series 28 selection specifications and question bank.
Finally, FINRA is proposing to make changes to the format of the content outline, including the preface, sample questions and reference materials. Among other changes, FINRA is proposing to: (1) Add a table of contents;
The number of questions on the Series 28 examination will remain at 95 multiple-choice questions, and candidates will continue to have 120 minutes to complete the examination. Currently, a score of 70 percent is required to pass the examination. The passing score for the revised Series 28 examination will be 69 percent.
The current Series 28 content outline is available on FINRA's Web site, at
FINRA is filing the proposed rule change for immediate effectiveness. FINRA proposes to implement the revised Series 28 examination program on December 14, 2015. FINRA will
FINRA believes that the proposed revisions to the Series 28 examination program are consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The updated examination aligns with the functions and associated tasks currently performed by an Introducing Broker-Dealer Financial and Operations Principal and tests knowledge of the most current laws, rules, regulations and skills relevant to those functions and associated tasks. As such, the proposed revisions would make the examination more efficient and effective.
Written comments were neither solicited nor received.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Robert W. Errett, Deputy Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On February 17, 2015, NYSE Arca, Inc. (“Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
On October 13, 2015, the Exchange withdrew the proposed rule change (SR-NYSEArca-2015-02), as modified by Amendment No. 1 thereto.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to extend the implementation rollout of its enhanced Options Floor Broker Management System, described in more detail below.
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.
Currently and until November 3, 2015, the Exchange operates two Floor Broker Management Systems concurrently on the options trading floor: The original Floor Broker Management System operating since 2005 (“FBMS 1”); and the enhanced Floor Broker Management System (“FBMS 2”). The purpose of the proposal is to continue the concurrent operation of FBMS 1 and FBMS 2 for a temporary period ending April 1, 2016 for the reasons stated below; otherwise the Exchange's concurrent operation of FBMS 1 and FBMS 2 would expire November 3, 2015.
FBMS 1 enables Floor Brokers and/or their employees to enter, route, and report transactions stemming from options orders received on the Exchange. FBMS 1 also establishes an electronic audit trail for options orders represented by Floor Brokers on the Exchange. Floor Brokers can also use FBMS 1 to submit orders to Phlx XL, rather than executing the orders in the trading crowd.
FBMS 2 was launched in March 2014. With FBMS 2, all options transactions on the Exchange involving at least one Floor Broker are required to be executed by FBMS 2. In connection with order execution, the Exchange allows FBMS 2 to execute two-sided orders entered by Floor Brokers, including multi-leg orders up to 15 legs, after the Floor Broker has represented the orders in the trading crowd. FBMS 2 also provides Floor Brokers with an enhanced functionality called the complex calculator that calculates and displays a suggested price of each individual component of a multi-leg order, up to 15 legs, submitted on a net debit or credit basis.
The Exchange received approval to implement FBMS 2 as of June 1, 2013,
The purpose of the delay was originally to repair FBMS 2, and then ultimately the Exchange determined to replace it with a new system. The Exchange contracted with a third-party entity to provide an alternative system (“FBMS 3”) to ultimately replace both FBMS 1 and FBMS 2. The Exchange had intended to implement FBMS 3 by November 3, 2015, but, based on recent estimates from the third-party entity, it will not be ready until March 2016. There were inadvertent delays in the construction of the new system.
During this additional time period, the Exchange will continue to permit Floor Brokers to use both FBMS 1 and FBMS 2 based on their business needs and Floor Brokers can choose whether to use one or both. Both FBMS 1 and FBMS 2 will continue to be available in
The Exchange believes that its proposal is consistent with Section 6(b) of the Act
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. The Exchange believes that permitting Floor Brokers to use both FBMS 1 and FBMS 2 for an additional period of time while the Exchange receives delivery of a new system should allow it to compete with other floor-based exchanges and help the Exchange's Floor Brokers compete with floor brokers on other options exchanges.
No comments were solicited. One comment letter was received by the Exchange when the Exchange communicated to the Floor Brokers that the old FBMS would be retired on September 1, 2014.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A)(iii) of the Act
The Exchange has requested that the Commission waive the 30-day operative delay. The Exchange has indicated that it has experienced performance issues with FBMS 2 and that it needs additional time to implement the new FBMS 3. Until FBMS 3 becomes available, the Exchange represents that it will continue to operate FBMS 1 and FBMS 2 concurrently and that all Floor Brokers may use either FBMS. Based on the foregoing, the Commission has determined to waive the 30-day operative date so that the proposal may take effect upon filing.
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.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to amend Commentary .13 to Rule 1012 (Series of Options Open for Trading), entitled “Mini Options Contracts.” Specifically, the Exchange proposes to replace the name “Google Inc.” with “Alphabet Inc.”
The Exchange requests that the Commission waive the 30-day operative delay period contained in Exchange Act Rule 19b-4(f)(6)(iii).
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to amend Commentary .13 to Rule 1012, regarding Mini Options traded on Phlx, to replace the name “Google Inc.” with “Alphabet Inc.” Google Inc. (“Google”) recently announced plans to reorganize and create a new public holding company, which will be called Alphabet Inc. (“Alphabet”). As a result of the holding company reorganization, each share of Class A Common Stock (“GOOGL”), which the Exchange has listed as a Mini Option, will automatically convert into an equivalent corresponding share of Alphabet Inc. stock.
The Exchange is proposing to make this change to Commentary .13 to Rule 1012 to enable the continued trading of Mini Options on Google's, now Alphabet's Class A shares. The Exchange is proposing to make this change because, on October 5, 2015 Google reorganized and as a result underwent a name change.
The purpose of this change is to ensure that Commentary .13 to Rule 1012 properly reflects the intention and practice of the Exchange to trade Mini Options on only an exhaustive list of underlying securities outlined in Commentary .13 to Rule 1012. This change is meant to continue the inclusion of Class A shares of Google in the current list of underlying securities that Mini Options can be traded on, while continuing to make clear that class C shares of Google are not part of that list as that class of options has not been approved for Mini Options trading. As a result, the proposed change will help avoid confusion.
The Exchange believes the proposed rule change is consistent with the Securities Exchange Act of 1934 (the “Act”) and the rules and regulations thereunder applicable to the Exchange and, in particular, the requirements of Section 6(b) of the Act.
In particular, the proposed rule change to change the name Google to Alphabet to reflect the new ownership structure is consistent with the Act because the proposed change is merely updating the current name associated with the stock symbol GOOGL to allow for continued mini option trading on Google's class A shares. The proposed change will allow for continued benefit
Phlx 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 does not impose any burden on intra-market competition because it applies to all members and member organizations uniformly. There is no burden on inter-market competition because the Exchange is merely attempting to continue to permit trading of GOOGL as a Mini Options, as is the case today. As a result, there will be no substantive changes to the Exchange's operations or its rules.
No written comments were either solicited or received.
Because the proposed rule change does not (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate if consistent with the protection of investors and the public interest, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
The Exchange has asked the Commission to waive the 30-day operative delay so that the proposal may become operative immediately upon filing. The Commission believes that waiving the 30-day operative delay is consistent with the protection of investors and the public interest, as it will allow the Exchange to continue to list mini options on the Google Class A shares, now Alphabet's Class A shares, following Google's reorganization. For this reason, the Commission designates the proposed rule change to be operative upon filing.
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.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act” or “SEA”)
FINRA is filing revisions to the content outline and selection specifications for the Financial and Operations Principal (Series 27) examination program.
The revised content outline is attached.
The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
Section 15A(g)(3) of the Act
NASD Rule 1022(b)(1) requires that each member that operates pursuant to the provisions of SEA Rule 15c3-1(a)(1)(ii),
• Final approval and responsibility for the accuracy of financial reports submitted to any duly established securities industry regulatory body;
• final preparation of such reports;
• supervision of individuals who assist in the preparation of such reports;
• supervision of and responsibility for individuals who are involved in the actual maintenance of the member's books and records from which such reports are derived;
• supervision and/or performance of the member's responsibilities under all financial responsibility rules promulgated pursuant to the provisions of the Act;
• overall supervision of and responsibility for the individuals who are involved in the administration and maintenance of the member's back office operations; or
• any other matter involving the financial and operational management of the member.
NASD Rule 1022(b)(3) provides that a person registered solely as a Financial and Operations Principal shall not be qualified to function in a principal capacity with responsibility over any area of business activity not described in paragraph (b)(2) of the rule.
In consultation with a committee of industry representatives, FINRA recently undertook a review of the Series 27 examination program. As a result of this review, FINRA is proposing to make revisions to the content outline to reflect changes to the laws, rules and regulations covered by the examination and to incorporate the functions and associated tasks currently performed by a Financial and Operations Principal. FINRA also is proposing to make changes to the format of the content outline.
The current content outline is divided into seven sections. The following are the seven sections and the number of questions associated with each of the sections, denoted Section 1 through Section 7:
1. Keeping And Preservation of Records and Broker-Dealer Financial Reporting Requirements, 15 questions;
2. Net Capital Requirements, 44 questions;
3. Customer Protection, 36 questions;
4. Municipal Securities Rulemaking Board—Regulations, 9 questions;
5. Extensions Of Credit In The Securities Industry, 8 questions;
6. Procedural Rules, 12 questions; and
7. Other Relevant Regulation and Interpretations, 21 questions.
Each section also includes the applicable laws, rules and regulations associated with that section. The current outline also includes a preface (addressing, among other things, the purpose, administration and scoring of the examination), sample questions and reference materials.
To develop the revised outline, FINRA conducted a job analysis study of Financial and Operations Principals, which included the use of a survey. The study provided detailed information regarding the day-to-day roles, responsibilities and job functions of Financial and Operations Principals. As a result, FINRA is proposing to revise the structure of the outline as described below to include functions and associated tasks that reflect the day-to-day activities of a Financial and Operations Principal.
Specifically, FINRA is proposing to divide the content outline into five major job functions that are performed by a Financial and Operations Principal. The following are the five major job functions, denoted Function 1 through Function 5, with the associated number of questions:
Function 1: Financial Reporting, 25 questions;
Function 2: Operations, General Securities Industry Regulations, and Preservation of Books and Records, 42 questions;
Function 3: Customer Protection, 24 questions;
Function 4: Net Capital, 41 questions; and
Function 5: Funding and Cash Management, 13 questions.
As noted above, each major job function includes an assigned number of questions. FINRA determined the number of questions for each function based on the results of the job analysis study. Thus, compared to the existing outline, the allocation of questions in the revised outline more closely reflects the current day-to-day activities of a Financial and Operations Principal.
Each function also includes specific tasks describing activities associated with performing that function. There are five tasks (1.1-1.5) associated with Function 1; three tasks (2.1-2.3) associated with Function 2; five tasks (3.1-3.5) associated with Function 3; seven tasks (4.1-4.7) associated with Function 4; and two tasks (5.1-5.2) associated with Function 5.
As noted above, FINRA also is proposing to revise the content outline to reflect changes to the laws, rules and regulations covered by the examination. Among other revisions, FINRA is proposing to revise the content outline to reflect the adoption of rules in the consolidated FINRA rulebook (
FINRA is proposing similar changes to the Series 27 selection specifications and question bank.
Finally, FINRA is proposing to make changes to the format of the content outline, including the preface, sample questions and reference materials. Among other changes, FINRA is proposing to: (1) Add a table of contents;
The number of questions on the Series 27 examination will remain at 145 scored multiple-choice questions,
The current Series 27 content outline is available on FINRA's Web site, at
FINRA is filing the proposed rule change for immediate effectiveness. FINRA proposes to implement the revised Series 27 examination program on December 14, 2015. FINRA will announce the proposed rule change and the implementation date in a
FINRA believes that the proposed revisions to the Series 27 examination program are consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The updated examination aligns with the functions and associated tasks currently performed by a Financial and Operations Principal and tests knowledge of the most current laws, rules, regulations and skills relevant to those functions and associated tasks. As such, the proposed revisions would make the examination more efficient and effective.
Written comments were neither solicited nor received.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Robert W. Errett, Deputy Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Securities and Exchange Commission (“Commission”).
Notice of an application for an order under section 12(d)(1)(J) of the Investment Company Act of 1940 (the “Act”) for an exemption from sections 12(d)(1)(A), (B), and (C) of the Act and under sections 6(c) and 17(b) of the Act for an exemption from sections 17(a)(1) and (2) of the Act. The requested order would permit certain registered open-end investment companies to acquire shares of certain registered open-end investment companies, registered closed-end investment companies, business development companies, as defined in section 2(a)(48) of the Act, and unit investment trusts (collectively, “Underlying Funds”) that are within and outside the same group of investment companies as the acquiring investment companies, in excess of the limits in section 12(d)(1) of the Act.
AAM ETF Trust, a Massachusetts business trust that intends to register under the Act as an open-end management investment company with multiple series and Advisors Asset Management, Inc., a Delaware Corporation registered as an investment adviser under the Investment Advisers Act of 1940.
The application was filed on August 20, 2015.
An order granting the requested relief will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on November 13, 2015 and should be accompanied by proof of service on the applicants, in the form of an affidavit, or, for lawyers, a certificate of service. Pursuant to Rule 0-5 under the Act, hearing requests should state the nature of the writer's interest, any facts bearing upon the desirability of a hearing on the matter, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission's Secretary.
Brent J. Fields, Secretary, U.S. Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090. Applicants: c/o Scott I. Colyer, Advisors Asset Management, Inc., 18925 Base Camp Road, Suite 203, Monument, Colorado 80132.
Barbara T. Heussler, Senior Counsel, at (202) 551-6990, or Mary Kay Frech, Branch Chief, at (202) 551-6821 (Division of Investment Management, Chief Counsel's Office).
The following is a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file
1. Applicants request an order to permit (a) a Fund
2. Applicants agree that any order granting the requested relief will be subject to the terms and conditions stated in the application. Such terms and conditions are designed to, among other things, help prevent any potential (i) undue influence over an Underlying Fund that is not in the same “group of investment companies” as the Fund of Funds through control or voting power, or in connection with certain services, transactions, and underwritings, (ii) excessive layering of fees, and (iii) overly complex fund structures, which are the concerns underlying the limits in sections 12(d)(1)(A), (B), and (C) of the Act.
3. Section 12(d)(1)(J) of the Act provides that the Commission may exempt any person, security, or transaction, or any class or classes of persons, securities, or transactions, from any provision of section 12(d)(1) if the exemption is consistent with the public interest and the protection of investors. Section 17(b) of the Act authorizes the Commission to grant an order permitting a transaction otherwise prohibited by section 17(a) if it finds that (a) the terms of the proposed transaction are fair and reasonable and do not involve overreaching on the part of any person concerned; (b) the proposed transaction is consistent with the policies of each registered investment company involved; and (c) the proposed transaction is consistent with the general purposes of the Act. Section 6(c) of the Act permits the Commission to exempt any persons or transactions from any provision of the Act if such exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act.
For the Commission, by the Division of Investment Management, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange proposes to amend its Fees Schedule. The text of the proposed rule change is available on the Exchange's Web site (
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
In March 2015, the Exchange launched Extended Trading Hours (“ETH”) for options on the S&P 500
The Exchange proposes to assess the same fees for SPXpm in the ETH session as are assessed for SPXpm in the Regular Trading Hours session (“RTH”).
Additionally, the Exchange notes that SPXpm transactions executed via AIM during ETH will be assessed AIM Agency/Primary and AIM Contra fees based on an order's origin code (which is currently the case during RTH as well).
The Exchange also proposes to apply in ETH, like RTH, an Index License Surcharge Fee of $0.13 per contract for SPXpm options for all non-customer orders. The surcharges are assessed to help the Exchange recoup license fees the Exchange pays to index licensors for the right to list S&P 500 Index-based products for trading.
CBOE Rule 6.1A (Extended Trading Hours) provides that the Exchange may approve one or more Market-Makers to act as Lead Market-Makers (“LMMs”) in each class during ETH in accordance with Rule 8.15A for terms of at least one month.
The Exchange also proposes to make a corollary change to Footnote 38. The Exchange notes that currently, for SPX and VIX options, LLMs [sic] are subject to a different rebate program.
The Exchange lastly notes that fees, rebates and programs that excluded SPXpm, during RTH will also not apply in ETH.
The Exchange believes the proposed rule change is consistent with the Securities Exchange Act of 1934 (the “Act”) and the rules and regulations thereunder applicable to the Exchange and, in particular, the requirements of Section 6(b) of the Act.
The proposed transaction fee amounts for SPXpm orders during the ETH session are reasonable, equitable and not unfairly discriminatory because they are the same as the amounts of corresponding fees for SPXpm orders during the RTH session. The Exchange notes that the fee amounts for each separate type of market participant will be assessed equally for each product to all such market participants (
Assessing the Index License Surcharge Fee of $0.13 per contract to SPXpm during ETH is reasonable because the amount is the same as the amount of the corresponding surcharge for SPXpm orders during RTH. The surcharge fee is equitable and not unfairly discriminatory because it will be assessed to all market participants to whom the SPXpm will apply in both RTH and ETH.
The Exchange believes it is reasonable, equitable and not unfairly discriminatory to offer LMMs in SPXpm during ETH that meet a certain heightened quoting standard (described above) a rebate of $1,000 per month given added costs that a LMM may undertake (
Finally, not applying in ETH fees, rebates and programs that exclude SPXpm during RTH is reasonable because these fees, rebates and programs will not apply to all TPHs and will be consistent across sessions.
The Exchange does not believe that the proposed rule changes will impose any burden on competition that are not necessary or appropriate in furtherance of the purposes of the Act. The Exchange does not believe that the proposed rule change will impose any burden on intramarket competition that is not necessary or appropriate in furtherance of the purposes of the Act because, while different fees and rebates are assessed to different market participants in some circumstances, these different market participants have different obligations and different circumstances. For example, Clearing TPHs have clearing obligations that other market participants do not have. Market-Makers have quoting obligations that other market participants do not have. There is a history in the options markets of providing preferential treatment to Customers, as they often do not have as sophisticated trading operations and systems as other market participants, which often makes other market participants prefer to trade with Customers. Further, the proposed fees, rebates and programs for ETH are intended to encourage market participants to bring liquidity to the Exchange during ETH (which benefits all market participants), while still covering Exchange costs (including those associated with the upgrading and maintenance of Exchange systems).
The Exchange does not believe that the proposed rule changes will impose any burden on intermarket competition that is not necessary or appropriate in furtherance of the purposes of the Act because SPXpm is a proprietary product that will only be traded on CBOE. To the extent that the proposed changes
The Exchange neither solicited nor received comments on the proposed rule change.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
60-day notice and request for comments.
The Small Business Administration (SBA) intends to request approval, from the Office of Management and Budget (OMB) for the collection of information described below. The Paperwork Reduction Act (PRA) of 1995, 44 U.S.C Chapter 35 requires federal agencies to publish a notice in the
Submit comments on or before December 22, 2015.
Send all comments to Gina Beyer, Program Analyst, Office of Disaster Assistance, Small Business Administration, 409 3rd Street, 6th Floor, Washington, DC 20416.
Gina Beyer, Program Analyst, Disaster Assistance,
A team of Quality Assurance staff at the Disaster Assistance Center (DASC) will conduct a brief telephone survey of customers to determine their satisfaction with the services received from the (DASC) and the Field Operations Centers. The result will help the Agency to improve where necessary, the delivery of critical financial assistance to disaster victims.
SBA is requesting comments on (a) Whether the collection of information is necessary for the agency to properly perform its functions; (b) whether the burden estimates are accurate; (c) whether there are ways to minimize the burden, including through the use of automated techniques or other forms of information technology; and (d) whether there are ways to enhance the quality, utility, and clarity of the information.
60-day notice and request for comments.
The Small Business Administration (SBA) intends to request approval, from the Office of Management and Budget (OMB) for the collection of information described below. The Paperwork Reduction Act (PRA) of 1995, 44 U.S.C Chapter 35 requires federal agencies to publish a notice in the
Submit comments on or before December 22, 2015.
Send all comments to Michael Simmons, Attorney Advisor, Office of Capital Access, Small Business Administration, 395 E Street, Patriots Plaza, Washington, DC 20416.
Michael Simmons, Attorney Advisor, Office of Capital Access,
Information collection is needed to ensure that Microloan Program activity meets the statutory goals of assisting mandated target market. The information is used by the reporting participants and the SBA to assist with portfolio management, risk management, loan servicing, oversight and compliance, data management and understanding of short and loan term trends and development of outcome measures.
SBA is requesting comments on (a) whether the collection of information is necessary for the agency to properly perform its functions; (b) whether the burden estimates are accurate; (c) whether there are ways to minimize the burden, including through the use of automated techniques or other forms of information technology; and (d) whether there are ways to enhance the quality, utility, and clarity of the information.
60-day notice and request for comments.
The Small Business Administration (SBA) intends to request approval, from the Office of Management and Budget (OMB) for the collection of information described below. The Paperwork Reduction Act (PRA) of 1995, 44 U.S.C Chapter 35 requires federal agencies to publish a notice in the
Submit comments on or before December 22, 2015.
Send all comments to Gina Beyer, Program Analyst, Office of Disaster Assistance, Small Business Administration, 409 3rd Street, 6th Floor, Washington, DC 20416.
Gina Beyer, Program Analyst, Disaster Assistance,
Prior to Small Business Administration (SBA) approval of subsequent loan disbursement, disaster loan borrowers are required to submit information to demonstrate that they used loan proceeds for authorized purposes only and to make certain certification regarding current financial condition and previously reported compensation paid in connection with the loan.
SBA is requesting comments on (a) Whether the collection of information is necessary for the agency to properly perform its functions; (b) whether the burden estimates are accurate; (c) whether there are ways to minimize the burden, including through the use of automated techniques or other forms of information technology; and (d) whether there are ways to enhance the quality, utility, and clarity of the information.
Title: Borrower's Progress Certification.
Description of Respondents: Disaster loan Borrowers.
Form Number: SBA Form 1366.
Total Estimated Annual Responses: 13,850.
Total Estimated Annual Hour Burden: 6,925.
60 Day Notice and request for comments.
The Small Business Administration (SBA) intends to request approval, from the Office of Management and Budget (OMB) for the collection of information described below. The Paperwork Reduction Act (PRA) of 1995, 44 U.S.C Chapter 35 requires federal agencies to publish a notice in the
Submit comments on or before December 22, 2015.
Send all comments to Louis Cupp, New Markets Policy Analyst, Investment, Small Business Administration, 409 3rd Street SW., 6th Floor, Washington, DC 20416.
Louis Cupp, New Market Policy Analyst, 202-619-0511
Form 857 is used by SBA examiners to obtain information about financing provided by small business investment companies (SBICs). This information, which is collected directly from the financed small business, provides independent confirmation of information reported to SBA by SBICs, as well as additional information not reported by SBICs.
60 Day Notice and request for comments.
The Small Business Administration (SBA) intends to request approval, from the Office of Management and Budget (OMB) for the collection of information described below. The Paperwork Reduction Act (PRA) of 1995, 44 U.S.C Chapter 35 requires federal agencies to publish a notice in the
Submit comments on or before December 22, 2015.
Send all comments to Brenda Washington, Senior Program Analyst, HUBZone, Small Business Administration, 395 E Street SW., Patriot Plaza, Washington, DC 20416.
Brenda Washington, Senior Analyst, 202-205-7663
The collected information is submitted by small business concerns seeking certification as a qualified HUBZone small business. SBA uses the information to verify a concern's eligibility for the HUBZone programs, to complied a database of qualified small business concerns, as well as for the re-certification and examination of certified HUBZone small business concerns. Finally SBA uses the information to prepare reports for the Executive and legislative branches.
U.S. Small Business Administration.
Notice.
This is a Notice of the Presidential declaration of a major disaster for Public Assistance Only for the State of Washington (FEMA-4242-DR), dated 10/15/2015.
Submit completed loan applications to: U.S. Small Business Administration, Processing and Disbursement Center, 14925 Kingsport Road, Fort Worth, TX 76155.
A Escobar, Office of Disaster Assistance, U.S. Small Business Administration, 409 3rd Street SW., Suite 6050, Washington, DC 20416.
Notice is hereby given that as a result of the President's major disaster declaration on 10/15/2015, Private Non-Profit organizations that provide essential services of governmental nature may file disaster loan applications at the address listed above or other locally announced locations.
The following areas have been determined to be adversely affected by the disaster:
The Interest Rates are:
The number assigned to this disaster for physical damage is 14503B and for economic injury is 14504B
U.S. Small Business Administration.
Notice.
This is a Notice of the Presidential declaration of a major disaster for Public Assistance Only for the State of South Carolina (FEMA—4241—DR), dated 10/15/2015.
Submit completed loan applications to: U.S. Small Business Administration, Processing and Disbursement Center, 14925 Kingsport Road, Fort Worth, TX 76155.
A. Escobar, Office of Disaster Assistance, U.S. Small Business Administration, 409 3rd Street SW., Suite 6050, Washington, DC 20416.
Notice is hereby given that as a result of the President's major disaster declaration on 10/15/2015, Private Non-Profit organizations that provide essential services of governmental nature may file disaster loan applications at the address listed above or other locally announced locations.
The following areas have been determined to be adversely affected by the disaster:
The Interest Rates are:
The number assigned to this disaster for physical damage is 14501B and for economic injury is 14502B.
Office of the United States Trade Representative.
Invitation for applications.
Chapter 19 of the North American Free Trade Agreement (“NAFTA”) provides for the establishment of a roster of individuals to serve on binational panels convened to review final determinations in antidumping or countervailing duty (“AD/CVD”) proceedings and amendments to AD/CVD statutes of a NAFTA Party. The United States annually renews its selections for the Chapter 19 roster. Applications are invited from eligible individuals wishing to be included on the roster for the period April 1, 2016, through March 31, 2017.
Applications should be received no later than November 20, 2015.
Applications should be submitted (i) electronically to
Katherine Wang, Assistant General Counsel, Office of the United States Trade Representative, (202) 395-6214.
Article 1904 of the NAFTA provides that a party involved in an AD/CVD proceeding may obtain review by a binational panel of a final AD/CVD determination of one NAFTA Party with respect to the products of another NAFTA Party. Binational panels decide whether such AD/CVD determinations are in accordance with the domestic laws of the importing NAFTA Party, and must use the standard of review that would have been applied by a domestic court of the importing NAFTA Party. A panel may uphold the AD/CVD determination, or may remand it to the national administering authority for action not inconsistent with the panel's decision. Panel decisions may be reviewed in specific circumstances by a three-member extraordinary challenge committee, selected from a separate roster composed of fifteen current or former judges.
Article 1903 of the NAFTA provides that a NAFTA Party may refer an amendment to the AD/CVD statutes of another NAFTA Party to a binational panel for a declaratory opinion as to whether the amendment is inconsistent with the General Agreement on Tariffs and Trade (“GATT”), the GATT Antidumping or Subsidies Codes, successor agreements, or the object and purpose of the NAFTA with regard to the establishment of fair and predictable conditions for the liberalization of trade. If the panel finds that the amendment is inconsistent, the two NAFTA Parties shall consult and seek to achieve a mutually satisfactory solution.
Annex 1901.2 of the NAFTA provides for the maintenance of a roster of at least 75 individuals for service on Chapter 19 binational panels, with each NAFTA Party selecting at least 25 individuals. A separate five-person panel is formed for each review of a final AD/CVD determination or statutory amendment. To form a panel, the two NAFTA Parties involved each appoint two panelists, normally by drawing upon individuals from the roster. If the Parties cannot agree upon the fifth panelist, one of the Parties, decided by lot, selects the fifth panelist from the roster. The majority of individuals on each panel must consist of lawyers in good standing, and the chair of the panel must be a lawyer.
Upon each request for establishment of a panel, roster members from the two involved NAFTA Parties will be requested to complete a disclosure form, which will be used to identify possible conflicts of interest or appearances thereof. The disclosure form requests information regarding financial interests and affiliations, including information regarding the identity of clients of the roster member and, if applicable, clients of the roster member's firm.
Section 402 of the NAFTA Implementation Act (Pub. L. 103-182, as amended (19 U.S.C. 3432)) (“Section 402”) provides that selections by the United States of individuals for inclusion on the Chapter 19 roster are to be based on the eligibility criteria set out in Annex 1901.2 of the NAFTA, and without regard to political affiliation. Annex 1901.2 provides that Chapter 19 roster members must be citizens of a NAFTA Party, must be of good character and of high standing and repute, and are to be chosen strictly on the basis of their objectivity, reliability, sound judgment, and general familiarity with international trade law. Aside from judges, roster members may not be affiliated with any of the three NAFTA Parties. Section 402 also provides that, to the fullest extent practicable, judges and former judges who meet the eligibility requirements should be selected.
The “Code of Conduct for Dispute Settlement Procedures Under Chapters 19 and 20” (
Section 402 establishes procedures for the selection by the Office of the United
Under Section 402, an interagency committee chaired by USTR prepares a preliminary list of candidates eligible for inclusion on the Chapter 19 Roster. After consultation with the Senate Committee on Finance and the House Committee on Ways and Means, the U.S. Trade Representative selects the final list of individuals chosen by the United States for inclusion on the Chapter 19 roster.
Roster members selected for service on a Chapter 19 binational panel will be remunerated at the rate of 800 Canadian dollars per day.
Eligible individuals who wish to be included on the Chapter 19 roster for the period April 1, 2016, through March 31, 2017, are invited to submit applications. Applications may be submitted either by fax to Sandy McKinzy at 202-395-3640 or electronically to
To submit an application via
The
Applications must be typewritten, and should be headed “Application for Inclusion on NAFTA Chapter 19 Roster.” Applications should include the following information, and each section of the application should be numbered as indicated:
1. Name of the applicant.
2. Business address, telephone number, fax number, and email address.
3. Citizenship(s).
4. Current employment, including title, description of responsibility, and name and address of employer.
5. Relevant education and professional training.
6. Spanish language fluency, written and spoken.
7. Post-education employment history, including the dates and addresses of each prior position and a summary of responsibilities.
8. Relevant professional affiliations and certifications, including, if any, current bar memberships in good standing.
9. A list and copies of publications, testimony, and speeches, if any, concerning AD/CVD law. Judges or former judges should list relevant judicial decisions. Only one copy of publications, testimony, speeches, and decisions need be submitted.
10. Summary of any current and past employment by, or consulting or other work for, the Governments of the United States, Canada, or Mexico.
11. The names and nationalities of all foreign principals for whom the applicant is currently or has previously been registered pursuant to the Foreign Agents Registration Act, 22 U.S.C. 611
12. List of proceedings brought under U.S., Canadian, or Mexican AD/CVD law regarding imports of U.S., Canadian, or Mexican products in which the applicant advised or represented (for example, as consultant or attorney) any U.S., Canadian, or Mexican party to such proceeding and, for each such proceeding listed, the name and country of incorporation of such party.
13. A short statement of qualifications and availability for service on Chapter 19 panels, including information relevant to the applicant's familiarity with international trade law and willingness and ability to make time commitments necessary for service on panels.
14. On a separate page, the names, addresses, telephone and fax numbers of three individuals willing to provide information concerning the applicant's qualifications for service, including the applicant's character, reputation, reliability, judgment, and familiarity with international trade law.
Current members of the Chapter 19 roster who remain interested in inclusion on the Chapter 19 roster only need to indicate that they are reapplying and submit updates (if any) to their applications on file. Current members do not need to resubmit their applications. Individuals who have previously applied but have not been selected must submit new applications to reapply. If an applicant, including a current or former roster member, has previously submitted materials referred to in item 9, such materials need not be resubmitted.
Applications normally will not be subject to public disclosure and will not be posted publicly on
Pursuant to section 402(c)(5) of the NAFTA Implementation Act, false statements by applicants regarding their personal or professional qualifications, or financial or other relevant interests that bear on the applicants' suitability for placement on the Chapter 19 roster or for appointment to binational panels, are subject to criminal sanctions under 18 U.S.C. 1001.
The following statements are made in accordance with the Privacy Act of 1974, as amended (5 U.S.C. 552a). The authority for requesting information to be furnished is section 402 of the NAFTA Implementation Act. Provision of the information requested above is voluntary; however, failure to provide the information will preclude your consideration as a candidate for the NAFTA Chapter 19 roster. This information is maintained in a system of records entitled “Dispute Settlement Panelists Roster.” Notice regarding this system of records was published in the
Federal Highway Administration (FHWA), DOT.
Notice.
This notice provides information regarding FHWA's finding that a Buy America waiver is appropriate for the use of non-domestic stainless steel grooved butterfly valves, grooved couplings, and electrical conduit bodies and fittings for the I-90 project in the State of Washington.
The effective date of the waiver is October 26, 2015.
For questions about this notice, please contact Mr. Gerald Yakowenko, FHWA Office of Program Administration, (202) 366-1562, or via email at
An electronic copy of this document may be downloaded from the Federal Register's home page at:
The FHWA's Buy America policy in 23 CFR 635.410 requires a domestic manufacturing process for any steel or iron products (including protective coatings) that are permanently incorporated in a Federal-aid construction project. The regulation also provides for a waiver of the Buy America requirements when the application would be inconsistent with the public interest or when satisfactory quality domestic steel and iron products are not sufficiently available. This notice provides information regarding FHWA's finding that a Buy America waiver is appropriate for use of non-domestic stainless steel grooved butterfly valves, grooved couplings, and electrical conduit bodies and fittings for the I-90 project in the State of Washington.
In accordance with Division K, section 122 of the “Consolidated and Further Continuing Appropriations Act, 2015” (Pub. L. 113-235), FHWA published a notice of intent to issue a waiver on its Web site (
In accordance with the provisions of section 117 of the SAFETEA-LU Technical Corrections Act of 2008 (Pub. L. 110-244, 122 Stat. 1572), FHWA is providing this notice as its finding that a waiver of Buy America requirements is appropriate. The FHWA invites public comment on this finding for an additional 15 days following the effective date of the finding. Comments may be submitted to FHWA's Web site via the link provided to the waiver page noted above.
(
Federal Highway Administration (FHWA), Department of Transportation (DOT).
Notice; response to comments.
This notice publishes the final designation of the highway-only Primary Freight Network (highway-only PFN). Section 167(d) of title 23, United States Code (U.S.C.) requires the Secretary of Transportation to establish the highway-only PFN and re-designate it every 10 years, giving consideration to certain factors. This designation meets the requirements of the law, but the Department and a multitude of public comments recognize that the highway-only PFN fails to demonstrate that freight moves through a complex and extensive network of highways, railroads, waterways, pipelines, and airways. While specific commodities are likely to be moved on a particular mode or series of modes, a complex multimodal system is required to carry the growing volume of bulk and high-velocity, high-value goods in the United States. In addition, the 27,000-mile cap required by the law does not yield a PFN representative of all the critical highway elements of the United States freight system. While the Department is designating the highway-only PFN to meet the statutory requirements of the authorizing law, the Department is concurrently and simultaneously proposing a comprehensive Multimodal Freight Network for public comment in the draft National Freight Strategic Plan to identify key infrastructure for all modes that is critical for the efficient movement of freight.
For questions about this program, contact Coral Torres, FHWA Office of Freight Management and Operations, (202) 366-7602, or by email at
You may retrieve a copy of the notice through the Federal eRulemaking portal at:
Section 167(c) of title 23, U.S.C., directs the Secretary to establish a National Freight Network (NFN) to assist States in strategically directing resources toward improved system performance for efficient movement of freight on the highway portion of the Nation's freight transportation system, including the National Highway System (NHS), freight intermodal connectors, and aerotropolis transportation systems.
Under 23 U.S.C. 167(c), the NFN will consist of three components: The highway-only PFN, the portions of the Interstate System not designated as part of the highway-only PFN, and Critical Rural Freight Corridors (CRFC), which are designated by the States.
The Moving Ahead for Progress in the 21st Century Act (MAP-21) limited the highway-only PFN to not more than 27,000 centerline miles of existing roadways that are most critical to the movement of freight. In addition, MAP-21 allowed an additional 3,000 centerline miles (that may include existing or planned roads) critical to the future efficient movement of goods on the highway-only PFN. The MAP-21 instructed DOT to base the highway-only PFN on an inventory of national freight volumes conducted by the FHWA Administrator, in consultation with stakeholders, including system users, transport providers, and States. The MAP-21 defined eight factors to consider in designating the highway-only PFN.
The eight factors are:
1. Origins and destinations of freight movement in the United States;
2. Total freight tonnage and value of freight moved by highways;
3. Percentage of annual average daily truck traffic in the annual average daily traffic on principal arterials;
4. Annual average daily truck traffic on principal arterials;
5. Land and maritime ports of entry;
6. Access to energy exploration, development, installation, or production areas;
7. Population centers; and
8. Network connectivity.
Section 167(d)(3) of title 23, U.S.C., mandates that the Secretary shall re-designate the highway-only PFN every 10 years. The highway-only PFN announced by this notice is the first iteration of the network.
Freight in America travels over an extensive network of highways, railroads, waterways, pipelines, and airways: 985,000 miles of Federal-aid highways; 141,000 miles of railroads; 28,000 miles waterways; and more than 2.6 million miles of pipelines. There are over 13,000 airports in the United States, with approximately 500 serving commercial operations, and over 5,000 coastal, Great Lakes, and inland waterway facilities moving cargo. While specific commodities are likely to be moved on a particular mode or series of modes, a complex multimodal system is required to carry the growing volume of bulk and high-velocity, high-value goods in the United States. For freight shipments moving more than 750 miles (the distance beyond which the benefits of multimodal shipping are more pronounced), 35 percent of U.S. freight by value (including air freight and mails) moves on multiple freight modes. And while 70 percent of freight by weight and 64 percent by value is moved by truck, the goods moved may be processed foods, manufactured goods or other finished products that were carried on other modes or include raw materials that traveled by other modes during an earlier stage of production.
Public comments on the draft highway-only PFN requested consideration of a network that was reflective of the Nation's entire multimodal freight system. While the DOT recognizes that freight is moved through the country by a complex multimodal system, MAP-21 mandated that the highway-only PFN consist solely of “existing roadways that are most critical to the movement of freight.” (23 U.S.C. 167(d)(1)(A)(ii)) As a result, the final highway-only PFN announced by this notice does not identify or prioritize other modal aspects of the U.S. freight system.
In recognition of the public comments indicating the need for a multimodal NFN that reflects the key components of each transportation mode in the nation's freight system, DOT is concurrently and simultaneously proposing a comprehensive Multimodal Freight Network (MFN) as part of the release of the National Freight Strategic Plan. The Department engaged all DOT modes with freight relevance (Federal Highway Administration, Federal Railroad Administration, Maritime Administration, Pipeline and Hazardous Materials Safety Administration and the Federal Aviation Administration) in building an MFN to identify key infrastructure for all modes that are critical for freight movement.
As part of this multimodal effort, DOT considered the feedback provided on the designation of the highway-only PFN (described below in this notice) and built a multimodal network using revised thresholds and a modified set of criteria, without the constraints of a mileage cap. This MFN was designed to satisfy the National Freight Policy goals and objectives at a multimodal level. The DOT will seek additional feedback from public and private transportation stakeholders in order to better identify what the goals, objectives and future use of this MFN will be at the regional, State, and local levels. The Department will also work with stakeholders to identify critical urban and rural connectors and corridors.
In the Generating Renewal, Opportunity, and Work with Accelerated Mobility, Efficiency, and Rebuilding of Infrastructure and Communities throughout America Act (GROW AMERICA), the Administration proposed to improve national freight policy to give it a multimodal focus. To this end, the GROW AMERICA would streamline existing law by eliminating the highway-only PFN and CRFCs and establish a multimodal NFN to inform public and private planning, to prioritize Federal investment, aid the public and private sector in strategically directing resources, and support Federal decisionmaking. This network would consist of connectors, corridors and facilities in all transportation modes most critical to the current and future movement of freight in the national freight system. The proposal would ensure a more accurate and relevant network by shortening the period of re-designation to a 5-year cycle and would require consideration of public input, including that from Metropolitan Planning Organizations (MPO) and States on critical freight facilities that are vital links in national or regionally significant goods movement and supply chains.
The purpose of this notice is to publish the final designation of the highway-only PFN as required by 23 U.S.C. 167(d), provide information about the methodology and data used in the designation, and provide an analysis of the comments received on the draft designation of this network.
With this notice, the FHWA Administrator, based on the delegation of authority by the Secretary, officially designates the final highway-only PFN. This final designation includes the same routes identified in the draft highway-only PFN, previously released on November 19, 2013 (78 FR 69520). Links illustrating the 26,966 miles on the highway-only PFN are available on the Web site maintained by FHWA (
On November 19, 2013, FHWA published the draft designation of the 27,000-mile highway-only PFN in the
Stakeholders requested additional time to analyze the draft highway-only PFN methodology, maps, and the highway-only PFN's potential impact on their communities. In response to these requests, FHWA twice extended the public comment period. The comment period closed on February 15, 2014, at which point the docket recorded a total of 307 responses, including over 1,200 discrete comments. The following section presents a quantitative and qualitative analysis of the trends, themes, and patterns identified in the public comments.
The initial highway-only PFN notice generated comments from a range of stakeholders in the private and public sectors. The following table identifies the number and percentage of comments received by organization type. The majority of comments came from MPOs, local government agencies, and State DOTs.
The FHWA asked stakeholders to review the draft highway-only PFN and provide feedback on five topics:
1. Specific route deletions, additions or modifications to the draft designation of the highway-only PFN as outlined in the notice;
2. The methodology for achieving a 27,000-mile final designation;
3. How the NFN and its components could be used by freight stakeholders in the future;
4. How the NFN may fit into a multimodal National Freight System; and
5. Suggestions for an urban-area route designation process.
Most responses addressed two or more of the five topics, with 33 percent focusing on the methodology and 21 percent commenting on route deletions, additions, or modifications.
The highway-only PFN Web site provides information on the requested additions, deletions and modifications to the highway-only PFN as well as a map reflecting these routes and segments, which totaled approximately 8,400 additional or modified miles and 230 miles proposed for deletion. This information can be found in the following Web site:
The majority of comments related to route changes suggested that FHWA consider the addition of specific road
1. Incorporating roads necessary for improving current freight movements;
2. Incorporating roads necessary for planning future commodity growth on the segment;
3. Affirming local freight planning efforts that identified the segment and/or facility as a major critical freight route or generator;
4. Incorporating roads necessary to close gaps and connect one facility, city, region, or State to another;
5. Incorporating roads necessary for resolving omissions of key segments and facilities such as those with major significance to national security and/or goods movement. Examples include: military facilities, airports, ports, bridges, rail yards and intermodal connectors;
6. Including the “first” and “last” mile of freight movements on routes designated in the draft highway-only PFN;
7. Incorporating a route or facility related to an international trade corridor;
8. Incorporating roads based on traffic counts and truck data indicating the segment is a critical link in the area's freight network;
9. Incorporating roads identified in the past by FHWA as a “Corridor of the Future” or that may become critical to the future movement of freight; and/or,
10. Including new, planned roads that, when constructed, will—
○ Provide continuity in the freight network;
○ Provide a connection to population centers;
○ Provide connectivity to intermodal facilities;
○ Relieve congestion on existing Interstates; and
○ Provide benefits to national commerce as a route in a long-distance trucking corridor.
Some respondents submitted requests for deletions and/or modifications to the highway-only PFN. The reasons offered for these requests included the following:
1. A desire to emphasize a different or more logical route than that included in the highway-only PFN (respondents often expressed that their agencies conducted evaluations using a different methodology or criteria that yielded other routes as more freight-relevant than the ones proposed in the draft highway-only PFN);
2. A desire to discourage non-local truck traffic through an area such as a neighborhood, commercial district, or downtown; requests to remove local streets not connected to freight facilities; and
3. Erroneous or outdated facility names.
The FHWA appreciates the comments requesting additions, deletions, or modifications to the draft highway-only PFN. In analyzing the route-related comments, FHWA determined that the level of information or data solicited in the draft highway-only PFN designation and provided through comments did not provide the specificity necessary to make accurate or consistent modifications to the network. For example, in order to change a route designation it is important to have mile marker identification of segments and common data years (in the case of data-driven segments). Although some respondents provided information such as beginning and end points or name of a route or facility (such as a specific intermodal connector), their requests to add, delete, or modify the designation of the routes and facilities did not comply with the criteria and threshold used for the draft designation, or different data sources were used as a justification.
Despite the lack of specificity in the data provided by commenters, many additions and modifications reflected some aspect that FHWA considers relevant for the efficiency, reliability, safety, and sustainability of the freight system and may have been incorporated into the highway-only PFN if not for the current mileage cap imposed by the law. Therefore, although no route modifications were made for the final designation of the highway-only PFN, FHWA considered these requests in its development of an alternative multimodal freight network, which is discussed in further detail in the National Freight Strategic Plan as displayed here:
Approximately 420 comments addressed the methodology for achieving a 27,000-mile designation. The commenters expressed concern regarding the complexity of the process for developing a highway-only PFN that incorporates the criteria identified in MAP-21 and appreciated the challenge of adhering to only 27,000 centerline miles of roads. Other comments were critical of the criteria, concept, and data used for the designation. The following subsections summarize comments on the methodology.
Comments regarding the highway-only PFN's centerline mileage threshold expressed concern that combining multiple network criteria with a mileage cap does not yield a highway-only PFN representative of the most critical highway elements of the United States freight system. Virtually all respondents preferred the sample 41,518-mile “comprehensive” (yet highway-only) network offered by DOT for comparison. Some respondents recommended that DOT work with Congress to develop statutory language to designate a more comprehensive and connected highway freight network that links directly to other freight modes. These commenters asked that Congress either (1) eliminate or raise the mileage threshold, or (2) use a corridor basis instead of the statutorily required centerline roadway mile basis. Some respondents sought a connected 27,000-mile network of key freight routes but did not provide a specific set of criteria. Others proposed that the highway-only PFN incorporate the entire Interstate System in a non-statutory designation. Respondents also noted that the comprehensive network (
Section 167 of title 23, U.S.C., specifies that the highway-only PFN designation cannot exceed a cap of 27,000 centerline roadway miles. Therefore, in order to comply with Federal law, the final highway-only PFN designation comprises no more than 27,000 centerline miles (and includes the LPOEs for the most freight-active border crossings by truck volumes).
This subsection discusses the comments on the statutory criteria and the methodology developed by FHWA for the highway-only PFN designation process. Some respondents proposed reconfiguring the highway-only PFN to connect significant freight origins and destinations for agriculture, energy production, manufacturing, mining, and national defense to other key infrastructure such as the Interstate system, ports of entry, and intermodal connectors. Some respondents expressed concern that agriculture was
In response, FHWA acknowledges that to better represent the movement of agricultural products on the freight system, it would be necessary to consider the data and the road-, rail-, air- and water-based routes of a multimodal freight system. National data shows agricultural products as being some of the top commodities under current models and forecasted trends. The current highway-only PFN methodology does not prioritize for type of commodity and was intended to be supplemented by CRFCs that could include routes serving key agricultural facilities. The FHWA believes a multimodal freight network map would more accurately depict the movement of agricultural commodities, which move by truck, rail, or barge, or combinations of these methods.
Respondents also expressed concern for the lack of sensitivity in the model to routes seasonal fluctuations and spikes in volumes that have low annual averages, such as agricultural or forest products routes and energy development, production, and extraction areas. They felt that the freight mileage on these routes does not meet the highway-only PFN threshold yet still accommodates a degree of truck traffic relevant for inclusion in the network. Some comments proposed a separate prioritization process for seasonally critical agricultural corridors beyond the CRFCs designation established in MAP-21 and a shorter re-designation cycle of the NFN and highway-only PFN to better capture these trends.
In response, FHWA acknowledges that additional research, data and refinements to the model could be developed to capture freight surges. The FHWA will consider opportunities for incorporating seasonality or surges into future network development.
Respondents also suggested modifications to the methodology and different thresholds for the criteria. Some noted that the initial step of the methodology should be changed to identify critical freight nodes. In this alternative methodology, the highway-only PFN would represent roadways that support certain critical freight nodes rather than a subset that carry the most freight (the format for the current methodology). The alternative methodology would then use additional analysis to define the subset of roadways most critical to serve these nodes. Respondents noted that by focusing on identifying critical roadways closest to freight nodes, this methodology would better assist States in strategically directing resources toward improved system performance for efficient movement of freight on the highway portion of the Nation's freight transportation system.
In response, FHWA notes that it explored the development of a highway-only PFN that started with critical freight nodes (predominantly urban areas and freight-intensive border crossings) and built out from these points. After analyzing the data and simulating the network, the Department selected a hybrid approach that used origin and destination data from the Freight Analysis Framework (FAF) and cross-referenced it with these nodes using Average Annual Daily Truck Traffic (AADTT) as a guide for how freight moves, by both tonnage and value, between nodes. There are many ways to develop the highway-only PFN, and that is in part why the FHWA sought public comment on the methodology. The FHWA felt that a node-based map would require leaving routes within a node undesignated, as FHWA lacked data specificity for these routes. As a result, use of a node-based map would require an additional step and time to obtain public input or to develop better data.
The comments noted that while the methodology itemized several factors considered for the draft network, it appears the base was drawn using AADTT and then adding or subtracting to accommodate each of the other factors. Respondents believed this may give undue weight to densely populated regions with the associated large regional distribution movements. Respondents also noted that this led to illogical results that appear to be related to data discrepancies between States.
Comments also addressed thresholds for the criteria used for designation. Several comments flagged the limits for AADTT and population used in the designation process as being too high. In particular, comments noted that the AADTT threshold of 8,500 trucks to identify roadway segments was set too high and precluded the establishment of a rational and connected national network, which they argued was the fundamental task of the national designation. Respondents advocated for a percent of trucks in the AADTT and a 1,500 AADTT threshold for the highway-only PFN. The commenters felt that these changes could provide a more useful picture of the freight economic corridors the Nation relies on to support interstate and international commerce.
Respondents also noted that the functional classification of roadways should be changed to include collectors and above, and to consider the allowance of lower vehicle classifications of truck traffic. Others argued that the percentage of trucks should not be the deciding factor but rather one of many factors considered for highway-only PFN designation, including connectivity to and between freight facilities. Finally, respondents believed the 25 percent AADTT requirement proposed for designating a CRFC corridor would be too restrictive for identifying urban area routes; they proposed using a separate data threshold for urban area freight corridor designation.
In response, FHWA acknowledges that AADTT levels had a fundamental role in the highway-only PFN designation process. The FHWA selected the AADTT and percent of truck traffic thresholds to meet the 27,000-mile limitation set in statute. The CRFC threshold of 25 percent truck traffic was set by statute in MAP-21. When identifying data from certain roadway classification and truck types, the FHWA focused on aspects of freight that would be most relevant to national goods movement, while also limiting the scope of the highway-only PFN to meet the mileage threshold.
Respondents expressed that to develop the highway-only PFN effectively, FHWA must provide a stronger consultative role for State DOTs to identify the critical individual State components of the highway-only PFN. They felt that FHWA should build as much flexibility into the designation process as possible, especially by providing the States with an
In response, FHWA agrees that involvement of State DOTs, MPOs, local agencies, and the private sector is key to developing a national or primary freight network. The FHWA also recognizes the need to have national consistency in the approach and scale of facilities included on a freight network. The FHWA encourages States to use State Freight Plans and to consult with State Freight Advisory Committees to identify facilities most critical to freight movement in each State.
A few comments recommended using the United States Census definition for urban areas instead of those with a population of 200,000 or more. In the Census definition, urbanized areas consist of territory that contains 50,000 or more people. Respondents criticized FHWA's use of the higher population threshold to meet the “arbitrary” limit of 27,000 centerline miles. Respondents noted that significant national and international trade flows to and from mid-size communities across the country are missed at the 200,000 population level.
In response, FHWA recognizes that the approach employed for connecting population areas of 200,000 or greater risks bypassing areas of important freight activity. However, FHWA encountered difficulty keeping the highway-only PFN to under 27,000 centerline roadway miles under scenarios that included all population centers of 50,000 or more people.
Furthermore, the lack of a stated application for the highway-only PFN and NFN introduced uncertainty into the designation process. Without a better understanding of the goals for the highway-only PFN, it was challenging to weight the factors for designation and to gauge which resulting network would best meet freight planning and investment needs. Each individual criterion yields different network coverage when compared to the other factors. The FHWA undertook an extensive research effort to fully understand the challenges of the proposed criteria and to develop a methodology that would generate the most comprehensive network. This resulted in dozens of scenarios that did not satisfy the mileage cap or the inclusion of all of the statutory criteria. The aggregation of these factors results in a map that is difficult to limit to 27,000 miles without some significant prioritization of the factors and their thresholds. Further, FHWA acknowledges that the 27,000-mile highway-only PFN does not meet the statutory criterion for network connectivity. To fix these problems, the alternative methodology applied by FHWA during the highway-only PFN development resulted in the second, comprehensive map that exceeded the statutory cap but is inclusive of all the criteria suggested in MAP-21 and reaches more population centers.
The majority of respondents expressed concern regarding the fragmented nature of the highway-only PFN. While it was widely understood that the non-contiguous highway-only PFN resulted from a need to meet competing statutory factors under a mileage threshold, respondents recommended that FHWA designate a continuous and linked multistate network of transportation infrastructure that provides a high level of support for international, national, and State economies. Some suggested the highway-only PFN use a corridor approach instead of the statutory requirement for measuring centerline roadway miles. Respondents agreed with FHWA's suggestion that corridor-level analysis and investment has the potential for widespread freight benefits and can improve the performance and efficiency of the highway-only PFN.
These respondents provided suggestions for a more comprehensive corridor-based approach to the highway-only PFN to designate multiple parallel routes in each region that provide a high level of support for international, national, and State economies and connect regional population and economic centers. Comments noted that the use of corridor miles rather than centerline miles would allow greater flexibility for States and local jurisdictions for funding opportunities and in applying future performance measures, not only to a single identified route but also to important intermodal and urban connectors as well as nearby parallel routes for use in freight-related congestion mitigation. In addition, commenters noted that these corridor designations will better correspond to a truly multimodal freight network to avoid or allow (as needed) route redundancies between all surface modes.
In response, FHWA agrees that a corridor approach for a highway network allows for coverage of multiple routes as well as freight facilities that satisfy the criteria in MAP-21. However, such an approach will not meet the centerline highway miles requirement of MAP-21. Also, because MAP-21 directed the Secretary to create a highway-only PFN, the lack of consideration of water freight and rail freight movements yields an incomplete representation of the nation's freight corridors.
The majority of comments that discussed the sources and limitations of data agreed that the national data sets utilized in the development of the draft highway-only PFN were insufficient to understand fully the behavior of freight at the regional and local levels. Respondents mentioned that the data used to develop the highway-only PFN do not accurately reflect freight movements at the State, regional, and local level and that the designation of this network relies on outdated information. Points raised included concerns that existing sources of data are fragmented, incomplete, and often not useful in supporting transportation operations, policy, and investment decisions. For example, one State noted that the Functional Classification Evaluations in their State had not been updated for over 20 years.
Respondents also expressed a view that the quality of the Highway Performance Monitoring System (HPMS) data, which were used to identify AADTT, varies greatly from State to State and depends upon the quantity and location of counts, the age and frequency of counts, and the upkeep of counting equipment. Respondents also felt that the highway-only PFN methodology did not take into account more complete and accurate data available from States, MPOs, and other local stakeholders. Comments suggested that FHWA coordinate with the States and their planning partners to ensure the currency and validity of the data sources that support the analyses conducted over the course of MAP-21 policy development and implementation. Respondents suggested that the next reauthorization fund a comprehensive data program that enables DOT, States, and MPOs to undertake the freight analysis and planning called for in MAP-21 at the national, State, and regional levels. Comments indicated that such a program should include safety data. Because significant freight facilities for energy transport appear in more remote areas and in outlying urban areas, respondents noted that data should capture information in rural and smaller outlying urban areas, as well as major metropolitan centers.
Comments noted that access to private sector data is needed as well as other
In response, FHWA notes that goods movement occurs in a very fluid environment. During the development of the draft highway-only PFN, and as an internal reference point of comparison to an earlier mapping effort, FHWA took the major freight corridors map that was originally developed for Freight Story 2008 and ran an analysis in the spring of 2013 to see how that map would look using current data. The Freight Story 2008 map contained 27,500 miles: 26,000 miles based on truck data and parallel intermodal rail lines and 1,500 miles representing goods movement on parallel major bulk rail lines or waterways. Using the same methodology with 2011 HPMS and rail data, data revealed that the mileage based solely on the truck and intermodal rail activity had grown to over 31,000 miles of roads since 2008, not including consideration of growth in other freight modes on parallel major bulk rail lines or waterways.
The FHWA recognizes that the data utilized for the development of the final highway-only PFN comprises the best information available on freight behavior at a national level. Nevertheless, national data is not sufficient to understand fully the behavior of freight at the regional and local levels. In particular, urban areas include a freight-generating population and in most cases, are the site of significant freight facilities where highway freight intersects with other modes at rail yards, ports, and major airports. These “first- and last- mile” connections, which also occur in rural areas, do not always show up in data sets. In order to develop a network that provides a better picture of freight in urban and rural areas, additional data collection at State and local levels is needed to improve the assessment of local and regional freight trends. This will require coordination with stakeholders at a local, State, and regional level. This data could provide a better understanding of seasonal and regional trends around the country that national data sets often do not capture.
The FHWA acknowledges a continuing national need for more robust data collection methods. The FHWA also acknowledges that additional coordination with MPOs and State DOTs is needed for future designation of the highway-only PFN and any other freight networks to address some of the data issues of the final highway-only PFN. As part of its development of an MFN and for any future designation of the highway-only PFN or other freight networks, DOT will seek additional coordination with MPOs and State DOTs to address some of the outlying issues remaining in this iteration of the network.
Because MAP-21 did not provide a specific purpose for the highway-only PFN, it was challenging to establish thresholds in the methodology and prioritize criteria to achieve the mileage limitation when it was unclear how the highway-only PFN and the NFN would be utilized. To better inform the process, FHWA sought comments on how the NFN and its components could be used by freight stakeholders in the future. A number of respondents echoed the concern that the future use of the NFN and highway-only PFN could not be identified without understanding its purpose and goals in relation to transportation policy and programs. Respondents requested additional information from DOT and Congress, with some recommending that the next transportation bill clearly identify a policy and provide funding for NFN or highway-only PFN facilities.
Many comments linked the highway-only PFN to funding, believing the highway-only PFN would be eventually be used to prioritize funding for projects. Some respondents proposed that Congress use this network for strategic investment in freight on a national network of key freight routes by specifically directing Federal highway funding through a formula program apportioned to States. They felt it would be appropriate for Congress to direct most of this funding to the NFN, with the addition of urban routes. There was concern about using the more limited highway-only PFN to allocate or apportion resources without making adjustments to the methodology. Suggestions for improving the map for directing investment included using the NFN, which includes the Interstate System, and adding urban routes, intermodal connectors, and last- and first-mile connectors.
Some respondents indicated funding should not be directed until the designation is vetted by States and MPOs and that resources should not be directed away from other highway programs to fund NFN-related projects. Respondents also suggested that DOT work with Governors to develop and evaluate funding options for a multimodal NFN that takes into account States' transportation infrastructure assets and limitations as detailed in State Freight Plans. The notice elicited concerns relating to restrictions on the ability to shift infrastructure funding to non-designated facilities and the potential assessment of freight user fees.
Other commenters were concerned that the NFN or highway-only PFN would be used in the future to impose restrictions on how the designated infrastructure could be used or impose minimum investment requirements. In addition, commenters raised concerns regarding the ease and speed of the re-designation process. Commenters also cautioned against using this network to direct the use of private property. Respondents requested that these and other potential issues be given consideration and that the government offer carefully structured and definitive guidance. In the absence of such guidance, respondents stated that they could not fully support the designation of any infrastructure, public or private, as a part of the highway-only PFN.
Respondents viewed the NFN as a tool to facilitate a closer working relationship between the government and private sectors who share an interest in a fully-functioning freight system. Having State DOTs, MPOs, trucking companies, the manufacturing and warehousing industries, and other highway freight stakeholders participate in a closer working relationship would be helpful to determine where limited highway funding can best be invested and where it will have the greatest and most widespread positive return on investment. Respondents supported the use of the network to strategically direct resources to improve system performance for efficient movement of freight on the highway portion of the National Freight System. They projected that the most important outcome would be the ability to identify and focus attention on the highways and related projects that would target freight mobility problems and lead to improved freight flow to maintain and enhance U.S. economic activity.
Respondents mentioned that the NFN may be a useful resource or tool in developing State Freight Networks and State Freight Plans. Respondents felt that designation of a highway-only PFN could aid States in such freight planning efforts as the designation of CRFCs, the development and update of State Freight Plans, input to State Freight Advisory Councils, and other planning activities. Respondents recommend that FHWA give greater weight to factors that States suggest, including consideration
Respondents commented that the highway-only PFN could provide the locations to target for valuable data collecting efforts to measure the fluidity of highway freight network. For example, the identification of segments with the highest AADTT could provide the location of potential capacity constraints and congestion issues.
In response, FHWA appreciates the concerns related to the lack of a stated application for the highway-only PFN and NFN. Without a better understanding of the goals for the highway-only PFN, the FHWA found it challenging to weight the factors for designation relative to one another and to gauge whether the resulting network would meet future public planning and investment needs. Each individual criterion yields different network coverage when compared to the simulations for the other factors. The aggregation of all the suggested criteria resulted in a map that was difficult to limit to 27,000 miles without some significant prioritization of the many factors and application of numerical thresholds in each measure.
The FHWA believes a multimodal NFN as described in the Department's GROW AMERICA surface transportation proposal will have the ability to inform public and private planning, to help prioritize for Federal investment, to aid the public and private sector in strategically directing resources, and to support Federal decisionmaking to achieve the national freight policy goals.
Respondents provided feedback on how the NFN fits into a larger multimodal national freight system and how to define a multimodal national freight system. Nearly 11 percent of the comments addressed this topic. The majority of respondents on this topic acknowledged that the highway-only PFN is a highway-only network and that the highway-only PFN and NFN are therefore incomplete in their representation of the multimodal system that is required to efficiently and effectively move freight in the United States. The FHWA agrees with these comments.
Comments suggested the highway-only PFN be designated in a way that would ensure future inclusion of the other freight modes that comprise the Nation's freight and goods transportation system. Respondents also voiced concern that the draft highway-only PFN did not include most of the segments that make up the first and last mile of key freight movements, which include local roads providing access to ports, intermodal facilities, rail yards, and other freight facilities. FHWA agrees with these comments.
Most respondents recognized these omissions were the result of the mileage cap and recommended FHWA advocate for the elimination of the mileage threshold. The FHWA agrees with these comments and has taken action by addressing this in both the Department's GROW AMERICA surface transportation proposal and the National Strategic Freight Plan.
Respondents believe that the highway NFN could be an important modal component of a multimodal national freight system, but that the NFN is not sufficient to describe the entirety of a system that moves freight by a variety of modes. The FHWA agrees with these comments.
Some comments strongly encouraged DOT to focus the National Freight Strategic Plan and other freight transportation work on the entire multimodal freight system, and recommended that the final highway-only PFN and NFN maps be overlaid with intermodal connectors, ports of entry, marine highways (waterborne routes), important inland river corridors and Class 1 rail lines to show a more comprehensive surface transportation network critical to the movement of freight. The FHWA agrees with these comments and has followed this recommendation.
Comments indicated the NFN should be combined with the other modes of transportation to form a true multimodal system that operates economically, efficiently, and harmoniously in the movement of freight both nationally and internationally. Respondents suggested building upon the FHWA's initial 41,518 centerline mile highway network as a basis for ultimately developing a more comprehensive, multimodal freight network. In addition, comments noted that FHWA and State DOTs should compare the highway freight network map with strategic freight railroad, waterway system, and aviation maps to locate connectivity gaps. Commenters recommended that highway routes connecting to intermodal facility locations be included in the NFN to ensure that the network reflects a well-connected multimodal freight system. The FHWA agrees with these comments and believes this is an activity that should be undertaken by DOT in consultation with States and MPOs.
Many respondents supported the expansion of this network to a more broadly defined multimodal network. They recommend that dedicated funding be made available to support projects included in an approved Regional Transportation Plan to enhance the performance and efficiency of the highway-only PFN and NFN, as well as to mitigate adverse freight movement impacts on surrounding communities and include eligibility for highway-rail grade separations and other mitigation projects located along nationally significant trade corridors.
In summary, FHWA agrees with the comments. In response to these recommendations, FHWA is providing the final designation of the highway-only PFN as required by MAP-21, while concurrently and simultaneously releasing a MFN as part of the National Freight Strategic Plan. The release of this Plan coincides with the issuance of this notice, and the Department will seek public comment on its proposed MFN.
State DOTs and MPOs provided comments in partnership with freight facility owners in support of a metropolitan area designation process similar to the CRFC designation. The comments included suggestions for methodologies and more precise data that could be used in the identification of these critical urban freight routes. Almost 14 percent of total comments related to this topic.
Supporters felt this additional network modification is necessary to improve the accuracy and utility of the highway-only PFN. These commenters felt that the next reauthorization should make provisions for designation of urban freight routes and connectors. It was noted that metropolitan areas are the economic engines of the 21st Century economy and that most of the population and most of the high-value and high-tech manufacturing is in metropolitan areas. Comments also noted that much of the cost of moving freight is the result of the congestion encountered in urban areas.
Respondents envisioned that the FHWA would reach out to local stakeholders to establish a formal urban-area route designation process and methodology. They felt strongly that State DOTs and urban representatives should be allowed to provide input on what factors might drive urban designations within the highway-only PFN. Respondents indicated they believe that State DOTs, MPOs, and other local agencies have the knowledge and data to identify the critical urban-area freight corridors and therefore these agencies should be responsible for
Some comments proposed that FHWA provide the framework and basic guidelines for designation, but give States the ultimate responsibility in establishing parameters and thresholds, in addition to identifying the routes for inclusion in the network. The limits to be set by the States and localities, as proposed by the commenters, would take into consideration the freight demand relative to a State's population, consumption and production, and commodity flows for designating both rural and urban freight systems.
Respondents suggested the use of the following criteria for the Critical Urban Freight Corridors (CUFC) designation: (1) High truck volume corridors; (2) strategic military facilities; (3) connections to major intermodal facilities; (4) significant freight intensive land uses on manufacturing and warehouse industrial lands; (5) energy exploration, development, installation, or production areas; (6) areas of significant congestion and delay for trucks; (7) locations of at-grade highway rail crossings; (8) number and severity of truck crashes; (9) geometric deficiencies that inhibit safe or efficient truck movement; (10) negative community/environmental impacts caused by truck traffic; (11) motor carrier enforcement and safety efforts; (12) availability of overnight or safe truck parking; (13) connections between major points of entry or key trip generators and the highway-only PFN (supported by locally derived data and analysis); (14) connectivity with the other elements of the NFN; and (15) freight value. Commenters did not support the inclusion of truck percent of AADT because they felt that it had little relevance in urban areas.
Respondents expressed the view that both the national freight strategy and the networks should include consideration for the urban first and last miles needed to make a complete freight trip.
Others suggested that FHWA should not set the thresholds for truck volume and percent for urban areas, but instead should require that each State set the truck volume and/or truck percent thresholds for their State. The commenters suggested that the context of percent truck traffic and/or truck volumes varied significantly across the country with regard to each State's consumption or production of goods and services and as a result, the thresholds should not be standardized for the Nation.
In addition, comments noted that States should be responsible for working with State freight stakeholders as well as MPOs and Rural Planning Organizations (RPO) in the designation of such systems within their respective State and that States should coordinate with neighboring States to ensure systems take into consideration multistate freight flows. They also noted that as with the CRFC designation process, this process should allow flexibility for States and metro areas to determine the most strategic and important freight routes.
Respondents believed that engaging State DOTs and MPOs in proposing urban-area freight routes would maximize the utility and relevance of each agency's existing freight planning processes, plans, and study initiatives. They felt that by elevating the responsibility of State and local entities to identify criteria, set targets, and identify CUFCs, freight planning would be in the forefront and freight plans would be aligned with other transportation, economic development, and environmental plans or programs.
In response, FHWA recognizes that many highway freight bottlenecks, chokepoints and first and last mile connectors are located in both rural and urban areas. This makes these areas critical to the efficiency of domestic and international supply chains. Although Federal law provided a mechanism to enable connectivity to critical freight “last mile” origins and destinations in rural areas through the designation of CRFC by the States, the language in 23 U.S.C. 167(d) lacks a parallel process for designating critical urban freight routes to address the need for connectivity to urban areas. Further, public and private sector representatives are increasingly emphasizing the significant role of cities and metropolitan areas in the safe and efficient movement of freight.
Given the lack of precision of national data at the urban level, FHWA believes there is merit in establishing a process for MPOs, RPOs, and State DOTs to designate critical urban freight routes and critical rural freight corridors that may have been missed when analyzing national-level data but are nonetheless important for freight movement to, from, and through an urban and rural areas. The FHWA recognizes that cities are best positioned to understand the complexities of freight movement in individual urban and rural areas, including current freight movement patterns, and plans or projections for shifts in freight movement within these areas, and could assist in the identification of thresholds for use in the designation of CUFCs.
In response to these comments, FHWA has begun developing preliminary concepts to aid in the designation of freight corridors should they be included in future legislation. The Department has also included language in GROW AMERICA surface transportation proposal that incorporates additional criteria in a NFN designation that gives consideration to bottlenecks and other impediments contributing to significant measurable congestion and delay in freight movement, facilities of future freight importance based on input from stakeholders, and an analysis of projections for future growth and changes to the freight system. In addition, the Department included language that considers elements of the freight system identified and documented by States and MPOs using national or local data as having critical freight importance to the region as part of the NFN.
Nearly 9 percent of total comments received mentioned funding. In general, respondents believe that the value of the highway-only PFN is limited without the provision of dedicated resources to address freight needs. Some referenced the need for these funds to maintain and enhance a multimodal national transportation system. Some commenters felt that existing Federal funding should not be diverted to the NFN unless current program funding levels could at least be maintained or expanded. Comments also noted that State DOTs and MPOs cannot fully comment on the impact of NFN designations without understanding the potential funding implications, which are not addressed in MAP-21. Further, they cautioned that the NFN should not be used to direct State or Federal investment in freight transportation systems until the network has been revised to reflect highways that serve continuous and efficient freight flow.
The commenters also suggested that planning and policy work would be of limited value if funds are not provided to realize the planning vision. Comments noted the highway-only PFN and an expanded multimodal national freight system could help make the case for a program that leverages local, regional, and private funds to invest in critical freight infrastructure needs.
Others respondents expressed concern about supporting a system that lacks connectivity and does not accurately represent freight trends. As previously discussed in this notice, some respondents recommended refraining from using the NFN for directing State or Federal investment in freight transportation systems. They noted that when the NFN has been
Most respondents expressed new funding should be prioritized to support sustainable economic vitality and global competitiveness for the U.S. Some respondents stated that this funding program should support national freight movement through enhancing the NFN by funding highway traffic count stations, truck weigh stations, truck rest area facilities, state of good repair for freight-traveled pavement and bridges, and operations management priorities such as congestion management and travel time reliability. Respondents suggested that funding could also be made available to support freight projects included in an approved Regional Transportation Plan or Transportation Improvement Program. In their view, these projects should be prioritized on the basis of demonstrable contribution to the performance and efficiency of the highway-only PFN and NFN, as well as to mitigate adverse freight movement impacts on surrounding communities.
Respondents also noted that although MAP-21 provides modest funding for the Projects of National and Regional Significance (PNRS), they felt that the PNRS program should be expanded to provide freight funding using a more robust, multimodal PFN. They suggest an expanded PNRS program should build on considerable past efforts, including the freight corridor designations and funding program established under the previous Federal transportation authorization, the Safe, Accountable, Flexible, Efficient Transportation Equity Act: A Legacy for Users (SAFETEA-LU).
In response, FHWA recognizes the need for additional freight investment in the U.S. That is why the GROW AMERICA proposes a six-year, $9 billion multimodal freight incentive program and a 6-year, $9 billion national freight infrastructure program. Given the increased emphasis on transportation performance management, FHWA believes it is prudent not to limit funding to a specific facility on a network map but to allow State and local governments, the private sector, and other entities to determine the best solutions to improving the safety and efficiency of the freight system through data and analysis in State Freight Plans and with the active engagement of the State Freight Advisory Committees.
The sections below summarize comments received on other issues raised in response to the solicitation of comments on the draft highway-only PFN.
Several comments raised concerns regarding the 10-year timeframe for updating the highway-only PFN. Comments expressed that this length of time does not reflect the changing nature of economic patterns and goods movement. Comments noted there are constant changes in market trends, population, infrastructure, technology, data, demographics, globalization, and investment. Respondents believe that a 10- or 20-year cycle will not allow policy makers and stakeholders to make optimal use of time, resources, and funding. With the MPO planning process based on a 4-year cycle, and freight and rail plans updated on 5-year cycles, respondents recommended FHWA pursue reducing the update cycle to match other metropolitan transportation planning cycles or at a minimum, provide an amendment process that enables States to request and receive approval for highway-only PFN changes between 10-year updates.
In response, FHWA agrees that the current 10-year update cycle is not sufficient. The FHWA does not have statutory authority to change the re-designation cycle but has proposed a 5-year update cycle in the GROW AMERICA surface transportation proposal. The Department will also be proposing a 5-year update cycle as part of the MFN in the National Strategic Freight Plan.
A small number of respondents raised the issue of highway safety and the highway-only PFN. Stakeholders noted that safety issues and performance measures should be considered in the establishment of the NFN. These comments emphasize that safety data needs to be part of the analysis and improving safety on our freight systems should be a goal of any Federal action related to the establishment of a NFN. Comments noted that factors should include freight moved by trucks, truck crash rates, the underlying causes of highway deaths and injuries, and infrastructure maintenance and vulnerabilities. Respondents noted that the highway-only PFN should take into account these interactions and impacts on the traveling public, especially if the highway-only PFN designation will increase truck traffic on those roadways.
In response, safety is the top priority for DOT and is a main goal of MAP-21's National Freight Policy. Although safety is not an express goal or factor in the designation of the highway-only PFN, each State's Strategic Highway Safety Plan (SHSP) affords a comprehensive approach and in-depth analysis for truck safety. The SHSPs are statewide, coordinated safety plans that provide a framework for reducing highway fatalities and serious injuries on all public roads. An SHSP identifies a State's key safety needs and guides investment decisions toward strategies and countermeasure with the most potential to save lives and prevent injuries. States are required to develop, implement, evaluate, and update an SHSP that identifies and analyzes highway safety problems and opportunities on all public roads.
Section 1118(b)(3) of MAP-21 requires that State Freight Plans include a description of how the plan will improve the ability of the State to meet the national freight goals established under section 167 of title 23, U.S.C., which include safety, and consideration of innovative technologies and operational strategies to improve the safety of freight movement. Sections 1118(b)(5) and (6) of MAP-21 also require consideration of routes projected to substantially deteriorate due to heavy vehicles and of areas of reduced mobility such as bottlenecks. The interim guidance for developing State Freight Plans pursuant to MAP-21 includes numerous safety elements.
There are data sources available to help States and MPOs measure these aspects of truck safety. The FHWA will work with our partners to ensure truck safety is considered and analyzed as appropriate in the SHSPs, as well as in State Freight Plans. The FHWA believes it is important to identify critical infrastructure through a multimodal freight network and to continue working with our partners and stakeholders to encourage actions to improve truck safety for these nationally significant areas and across the Nation's roadways.
Respondents noted that the highway-only PFN designation does not
In response, FHWA acknowledges the importance of understanding and mitigating the negative effects of freight on the environment and on communities. Freight projects, like other transportation projects, should consider and address environmental justice and access, air quality, water quality, and noise pollution, for example. With respect to mapping a freight network to reflect these aspects, however, the NFN and highway-only PFN requirements do not include factors relating to the environment or public health. The MAP-21 directed the Department to designate “not more than 27,000 centerline miles of existing roadway that are most critical for the movement of freight” in an NFN that is focused on “improved system performance for efficient movement of freight.” Further, national-level environmental data is limited in being able to offer a comprehensive assessment of these issues. In order to meet the various Federal requirements and advance human and environmental protection, the FHWA believes it is important to first identify the critical infrastructure in a multimodal freight network and then work with our partners and stakeholders to protect the environment and public health.
Several respondents discussed the inclusion of private roads and rail lines, with many calling for the incorporation of private rail systems in a multimodal PFN. However, respondents representing railroads expressed concern that there is no information as to how a designation of a facility as part of the highway-only PFN will be used in the future. As discussed more generally in the previous section on “NFN Use by Freight Stakeholders in the Future,” commenters urged DOT to define the highway-only PFN's purpose before determining whether to include private infrastructure on the highway-only PFN or the NFN. Railroad stakeholders were concerned that Congress would establish minimum investment requirements or restrict future uses of the rail infrastructure. They questioned whether designation of private rail facilities would have consequences for funding decisions for these facilities, impact the ability to shift infrastructure funding to non-designated facilities, or result in freight user fees.
In response, FHWA acknowledges there are potential challenges related to designating private infrastructure as part of a highway-only PFN or NFN. However, because the Nation's multimodal freight system is comprised of both public and private infrastructure and the interdependencies, redundancies, and efficiencies of this entire network is relevant to understanding freight movement, it would be very beneficial to national and regional planning to include both types in a multimodal freight network. This is why we are concurrently and simultaneously releasing the draft Nation Freight Strategic Plan. The FHWA will continue to consider the implications of designating private and non-Federal infrastructure as they relate to the goals, objectives, and a future purpose of an MFN.
Some respondents supported incorporating all intermodal connections, arguing that this was imperative in building a seamless highway-only PFN. Respondents also highlighted the importance of having an updated listing of NHS freight intermodal connectors on the highway-only PFN map. Respondents recommended that intermodal connectors, specifically if they are adjacent to a trade gateway, major industrial, distribution and consumption area, seaport, river terminal or designated freight corridor, be prioritized for inclusion in the final highway-only PFN. Specific comments requested the inclusion of marine highways and urban intermodal connectors. Respondents also supported establishing a formal process for designating critical urban and rural freight routes that include first and last miles and/or intermodal connectors.
Comments touched on the need to include in the highway-only PFN more than just the intermodal connectors occurring in population centers of 200,000 or more. While the majority of commenters understood why FHWA chose to use the metric of AADTT to identify which segments of the NHS would appear on the highway-only PFN, there was confusion about why AADTT was not also used to measure and select intermodal connectors. Commenters were concerned with the fact that data sources used to analyze the intermodal connectors are incomplete. The respondents strongly recommended that FHWA consult with State DOTs, which, by working with their regional and local partners could assist the Federal Government in identifying routes that will ensure network connectivity to nationally significant intermodal facilities.
In response, FHWA agrees that NHS intermodal connectors are vital elements of the NFN. If the highway-only PFN was not mileage-constrained at 27,000 miles, priority consideration would be given to including all relevant urban and non-urban NHS freight intermodal connectors (these are included in the 41,518 mile comprehensive network). To adhere to the mileage cap, FHWA excluded those not meeting the AADTT threshold from the highway-only PFN. Regarding data, FHWA's listing of NHS intermodal connectors is current. However, FHWA does not have comprehensive data on the conditions and performance of each NHS intermodal connector. The FHWA supports efforts by infrastructure owners to collect comprehensive data on these facilities and update it on a frequent basis to help measure the performance of these connectors. The FHWA is conducting a research study to assess the conditions and performance of a representative sample of intermodal connectors. This information will assist the agency, its partners, and infrastructure owners in better assessing the current use of freight intermodal connectors, freight connector condition and performance, and in identifying connector impediments and solutions to allocate resources for the efficient flow of goods.
Respondents requested that FHWA add strategic military bases to the origins and destinations of freight movements to be considered in the highway-only PFN designation. Comments indicated this would help provide for logistics that support a strong national defense. Respondents sought inclusion of U.S. Military Power
In response, FHWA acknowledges the importance of a variety of modes and types of facilities for the efficient movement of freight for the U.S. Armed Forces. The FHWA believes there are various national highway systems that have already been designated to meet the specific needs of the military and transportation of equipment and supplies. These systems include the U.S. Interstate Highway System, which was in part based on roads necessary for national defense, and the Strategic Highway Network (STRAHNET). The STRAHNET and the Strategic Rail Corridor Network were established as critical to DOD domestic operations, such as emergency mobilization and peacetime movement of heavy armor, fuel, ammunition, repair parts, food, and other commodities to support U.S. military operations. As a result, FHWA does not think access to every military base or strategic port needs to be part of the highway-only PFN. The DOT will consider how best to include them on the MFN. The FHWA has identified a number of intermodal connectors under the 41,000 comprehensive networks that connect to military bases/facilities and will include these NHS freight intermodal connectors in future designations of the highway-only PFN if the mileage cap is increased. In addition, the entire mileage of the final highway-only PFN is part of STRAHNET.
The Secretary of Transportation established the National Freight Advisory Committee (NFAC) in 2013 to provide advice and recommendations on matters related to freight transportation in the United States. This Committee is composed of representatives from the public and private sector, local and State governments, labor unions, safety organizations, transportation organizations, freight shipping companies, and other freight stakeholder organizations. The NFAC undertook an extensive review of the draft designation of the highway-only PFN and provided the comments and recommendations, which can be found here:
The NFAC stated that it did not endorse the proposed highway-only PFN and directed its comments to both Congress and DOT. Its primary concerns were related to the size and nature of the 27,000 centerline miles limitation and the need for a multimodal freight network. The NFAC felt the draft highway-only PFN lacked critical elements of first and last mile connectors, especially in urban areas, as well as port connectors and North American gateway connections. The Committee preferred a hub- and corridor-based, multimodal approach for designation and opposed the statutory imposition of a mileage threshold. They urged DOT to proceed with a multimodal network, engaging the public and including an urban designation process. They supported the use of AADTT in a highway-only PFN. In the absence of a revised highway-only PFN, they preferred that funding be prioritized to solve truck congestion on existing freight corridors and gateways.
Regarding the lack of a stated purpose for the PFN, the NFAC felt DOT should develop goals in coordination with a variety of public and private sector stakeholders and use these goals to inform the development of the Conditions and Performance Report and the National Freight Strategic Plan. They felt that these goals must address the intended use of the highway-only PFN, whether it should have a role in prioritizing needs or justifying investment, and why it did not give full consideration to first or last mile segments. According to the NFAC, the lack of goals impedes the ability to have a national investment strategy.
When highway-only PFN goals are established, the NFAC believes flexible investment strategies should be afforded to the States and private railroads should retain their autonomy to manage their infrastructure. They called on Congress in the next reauthorization to provide for a comprehensive data program and for access to private sector data and other sources to support freight planning. They cited the value of State Freight Plans and State Freight Advisory Committees in informing national planning and sought to make these mandatory. There was strong support for local and State leadership in designating urban freight networks. They called on DOT to consider and incorporate future trends in goods movement, and to re-designate or modify more frequently than the 10-year cycle. The NFAC urged the creation of dedicated funding from additional revenue sources to support both planning and to incentivize investment in projects.
The NFAC further recommended that DOT consider where freight should be encouraged to move as opposed to only reflecting current movements. The Committee requested the location of structurally deficient bridges or “freight restricted bridges” be considered for the highway-only PFN. They also submitted the following list of routes they felt was missing from the highway-only PFN:
• Primary high-traffic connectors between freight terminals and Interstate highways;
• Intermodal connectors, connections to logistics centers and manufacturing centers (freight origin and destination points);
• Highway segments that provide unique through-routes for 53-foot national standard tractor-trailers;
• Metropolitan components and urban connectors;
• Critical highways based on where activity is happening, not just those on the Interstate system (non-Interstate networks);
• Farm-to-market routes;
• Waterways;
• International gateways such as highway border crossings, airports, seaports, Great Lakes ports and river terminals that provide significant freight movement; and
• Interstate crossings connecting urban areas with national manufacturers and distribution centers in different states.
Section 167(c) of title 23, U.S.C., directed the Secretary to establish a NFN to assist States in strategically directing resources toward improved system performance for efficient movement of freight on the highway portion of the Nation's freight
In undertaking the highway-only PFN designation, FHWA developed multiple scenarios to identify a network that represents the most critical highway portions of the United States freight system. The highway-only PFN was informed by measurable and objective national data. In performing the analysis that led to the development of the highway-only PFN, FHWA considered the following criteria and data sources, which are further described at the listed Web locations:
The FHWA developed the following methodology with the intention of generating a network that could include as many of the MAP-21 criteria as practicable. The FHWA undertook extensive research and numerous approaches to better understand and model the criteria. This research informed our finding that compliance with the mileage cap yields a network that does not sufficiently accommodate the full set of criteria. In order to comply with the mileage cap while still accommodating the statutory criteria, FHWA developed a methodology that prioritized the application of the criteria and set thresholds within the data sets. The FHWA used the following methodology to develop the highway-only PFN:
(1) Used the FAF and HPMS data sets to generate the top 20,000 miles of road segments that qualified in at least two of the following four factors: Value of freight moved by highway; tonnage of freight moved by highway; AADTT on principal arterials; and percentage of AADTT in the annual average daily traffic on principal arterials.
(2) Analyzed the segments identified in Step 1 and gaps between segments for network connectivity. Created the network by connecting segments if the gap between segments was equal to or less than 440 miles (440 miles being the distance a truck could reasonably travel in 1 day). Eliminated a segment if it was less than one-tenth of the length of the nearest qualifying segment on the highway-only PFN.
(3) Identified land ports of entry with truck traffic higher than 75,000 trucks per year. Connected these land ports of entry to the network created in Steps 1 and 2.
(4) Identified the NHS Freight Intermodal Connectors within urban areas with a population of 200,000 or more.
(5) Identified road segments within urban areas with a population of
(6) Analyzed the network to determine the relationship to population centers, origins and destinations, ports, river terminals, airports, and rail yards and added minor network connectivity adjustments.
(7) Analyzed the road systems in Alaska, Hawaii, and Puerto Rico using HPMS data. These routes would not otherwise qualify under a connected network model but play a critical role in the movement of products from the agriculture and energy sectors, as well as international import/export functions for their States and urban areas and added roads connecting key seaports to population centers.
(8) Analyzed the network to determine the relationship to energy exploration, development, installation, or production areas. Since the data points for the energy sector are scattered around the United States, often in rural areas, and because some of the related freight may move by barge or other maritime vessel, rail, or even pipeline, FHWA did not presume a truck freight correlation.
(9) Steps 1 through 8 resulted in a network of 41,518 centerline miles, including 37,436 centerline miles of Interstate and 4,082 centerline miles of non-Interstate roads.
The FHWA has posted the details of the final initial highway-only PFN, including the 26,966-mile highway-only PFN map, State maps, and lists of designated routes and tables of mileage by State at:
This final highway-only PFN, which is unchanged from the draft released in November 2013, attempts to reflect the many criteria established in MAP-21 while also complying with the mileage cap. As a result, the highway-only PFN results in an unconnected network with major gaps in the system, including components of the global and domestic supply chains. Therefore, DOT is concurrently and simultaneously developing an MFN as part of the National Freight Strategic Plan that better represents the complex multimodal freight system in the U.S. and has proposed the GROW AMERICA legislation that is responsive to the many public comments outlined in this notice.
23 U.S.C. 167; 49 CFR 1.85.
Federal Highway Administration (FHWA), DOT.
Notice.
This notice provides information regarding FHWA's finding that a Buy America waiver is appropriate for the use of non-domestic fabrication of cable mesh for 8′-0″ high oxidized stainless steel cable net safety fence on Interstate 5, MP 28.7 in San Diego, California.
The effective date of the waiver is October 26, 2015.
For questions about this notice, please contact Mr. Gerald Yakowenko, FHWA Office of Program Administration, (202) 366-1562, or via email at
An electronic copy of this document may be downloaded from the
The FHWA's Buy America policy in 23 CFR 635.410 requires a domestic manufacturing process for any steel or iron products (including protective coatings) that are permanently incorporated in a Federal-aid construction project. The regulation also provides for a waiver of the Buy America requirements when the application would be inconsistent with the public interest or when satisfactory quality domestic steel and iron products are not sufficiently available. This notice provides information regarding FHWA's finding that a Buy America waiver is appropriate for use of non-domestic fabrication process to convert the stainless steel products into safety cable mesh. The stainless steel product for the cable mesh is produced domestically in the United States. However, there is no domestic manufacturer capable of fabricating the stainless steel products into safety cable mesh.
In accordance with Division K, section 122 of the “Consolidated and Further Continuing Appropriations Act, 2015” (Pub. L. 113-235), FHWA published a notice of intent to issue a waiver on its Web site (
In accordance with the provisions of section 117 of the SAFETEA-LU Technical Corrections Act of 2008 (Pub. L. 110-244, 122 Stat. 1572), FHWA is providing this notice as its finding that a waiver of Buy America requirements is appropriate. The FHWA invites public comment on this finding for an additional 15 days following the effective date of the finding. Comments may be submitted to FHWA's Web site via the link provided to the waiver page noted above.
23 U.S.C. 313; Pub. L. 110-161, 23 CFR 635.410.
Norfolk Southern Railway Company (NSR), pursuant to a written trackage rights agreement dated July 31, 2015, has agreed to grant limited local trackage rights to the Terminal Railroad Association of St. Louis (TRRA) over approximately 0.49 miles of rail line in St. Louis, Mo. (the Line). Specifically, TRRA will acquire trackage rights between TRRA's connection with NSR at approximately North Market Street, St. Louis, Mo., and the Kiesel Facility at approximately Dock Street, St. Louis, Mo.
TRRA may consummate its acquisition on or after November 7, 2015, the effective date of the exemption (30 days after the verified notice of exemption was filed).
TRRA states that NSR, who currently operates over TRRA via trackage rights to access the Line and serve the Kiesel Facility, intends to discontinue a nearby two-mile segment of trackage. According to TRRA, granting TRRA limited local trackage rights over the Line for the sole purpose of serving the Kiesel Facility (the only active shipper accessible via the Line) will allow NSR and TRRA to operate more efficiently in this area after NSR's nearby discontinuance while also preserving rail service to an existing customer. TRRA will assume maintenance of the Line until NSR decides to resume active operations over the Line.
As a condition to this exemption, any employees affected by the trackage rights will be protected by the conditions imposed in
This notice is filed under 49 CFR 1180.2(d)(7). If the notice contains false or misleading information, the exemption is void ab initio. Petitions to revoke the exemption under 49 U.S.C. 10502(d) may be filed at any time. The filing of a petition to revoke will not automatically stay the effectiveness of the exemption. Petitions for stay must be filed by October 30, 2015 (at least seven days before the exemption becomes effective).
An original and 10 copies of all pleadings, referring to Docket No. FD 35962, must be filed with the Surface Transportation Board, 395 E Street SW., Washington, DC 20423-0001. In addition, a copy of each pleading must be served on Asim S. Raza, Terminal Railroad Association of St. Louis, 415 S. 18th Street, Suite 200, St. Louis, MO 63103.
Board decisions and notices are available on our Web site at
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Martin Marietta Materials, Inc. (MMM), a noncarrier, has filed a verified notice of exemption under 49 CFR 1180.2(d)(2) to acquire control of Rock & Rail, Inc. (RRI), a Class III rail carrier.
According to MMM, it currently controls Alamo North Texas Railroad (ANT),
MMM states that: (i) The railroads do not connect with each other or any railroad in their corporate family; (ii) the proposed transaction is not part of a series of anticipated transactions that would connect the railroads with each other or any railroad in their corporate family; and (iii) the transaction does not involve a Class I carrier. Therefore, the transaction is exempt from the prior approval of requirements of 49 U.S.C. 11323.
Under 49 U.S.C. 10502(g), the Board may not use its exemption authority to relieve a rail carrier of its statutory obligation to protect the interests of its employees. Section 11326(c), however, does not provide for the labor protection for transactions under §§ 11324 and 11325 that involve only Class III rail carriers. Because this transaction involves Class III rail carriers only, the Board, under the statute, may not impose labor protective conditions for this transaction.
If the verified notice contains false or misleading information, the exemption is void ab initio. Petitions to revoke the exemption under 49 U.S.C. 10502(d) may be filed at any time. The filing of a petition to revoke will not automatically stay the transaction. Petitions to stay must be filed no later than October 30, 2015 (at least seven days before the exemption becomes effective).
An original and ten copies of all pleadings referring to Docket No. FD 35966, must be filed with the Surface Transportation Board, 395 E Street SW., Washington, DC 20423-0001. In addition, a copy of each pleading must be served on William A. Mullins, Baker & Miller PLLC, 2401 Pennsylvania Ave. NW., Suite 300, Washington, DC 20037.
Board decisions and notices are available on our Web site at
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Caldwell Railroad Commission (CRC) has filed an amended verified notice of exemption under 49 CFR pt. 1152 subpart F—
CRC has certified that: (1) No freight traffic has moved over the Line for at least two years; (2) any overhead traffic over the Line can and has been rerouted; (3) no formal complaint filed by a user of rail service on the Line (or by a state or local government entity acting on behalf of such user) regarding cessation of service over the Line is either pending with the Surface Transportation Board (Board) or with any U.S. District Court or has been decided in favor of complainant within the two-year period; and (4) the requirements at 49 CFR 1105.7(c) (environmental report), 49 CFR 1105.11 (transmittal letter), 49 CFR 1105.12 (newspaper publication), and 49 CFR 1152.50(d)(1) (notice to governmental agencies) have been met.
As a condition to this exemption, any employee adversely affected by the abandonment shall be protected under
Provided no formal expression of intent to file an offer of financial assistance (OFA) has been received, this exemption will be effective on November 24, 2015, unless stayed pending reconsideration. Petitions to stay that do not involve environmental issues,
A copy of any petition filed with the Board should be sent to CRC's representative: David H. Coburn, Steptoe & Johnson LLP, 1330 Connecticut Ave. NW., Washington, DC 20036.
If the verified notice contains false or misleading information, the exemption is void ab initio.
CRC has filed environmental and historic reports that address the effects, if any, of the abandonment on the environment and historic resources. OEA will issue an environmental assessment (EA) by October 30, 2015. Interested persons may obtain a copy of the EA by writing to OEA (Room 1100, Surface Transportation Board, Washington, DC 20423-0001) or by calling OEA at (202) 245-0305. Assistance for the hearing impaired is available through the Federal Information Relay Service at (800) 877-8339. Comments on environmental and historic preservation matters must be filed within 15 days after the EA becomes available to the public.
Environmental, historic preservation, public use, or interim trail use/rail banking conditions will be imposed, where appropriate, in a subsequent decision.
Pursuant to the provisions of 49 CFR 1152.29(e)(2), CRC shall file a notice of consummation with the Board to signify that it has exercised the authority granted and fully abandoned the Line. If consummation has not been effected by CRC's filing of a notice of consummation by October 23, 2016, and there are no legal or regulatory barriers to consummation, the authority to abandon will automatically expire.
Board decisions and notices are available on our Web site at
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Office of the Departmental Chief Information Officer, Office of the Secretary of Transportation, DOT.
Notice of retirement of one Privacy Act system of records.
In accordance with the Privacy Act of 1974, the Department of Transportation (DOT) is giving notice that it will retire the following Privacy Act system of records: DOT/ALL 18, International Freight Data System (IFDS) (April 14, 2008, 73 FR 20084). The IFDS was never implemented by the DOT and the DOT will continue to rely upon the U.S. Customs and Border Protection's Automated Commercial Environment/International Trade Data System for its data needs.
This change will take effect upon publication.
For questions, please contact: Claire W. Barrett, Departmental Chief Privacy Officer, Privacy Office, Department of Transportation, Washington, DC 20590;
Pursuant to the provisions of the Privacy Act of 1974, 5 U.S.C. 552a, and as part of its ongoing integration and management efforts, DOT is retiring the system of records notice, DOT/ALL 18 International Freight Data System (IFDS) (April 14, 2008, 73 FR 20084), which was intended to be an automated system that provided participating DOT Operating Administrations with international commercial information to perform their enforcement, statistical, analytical, modeling and policy responsibilities. The IFDS was never implemented by the DOT and the DOT will continue to rely upon DHS/CBP-001, Automated Commercial Environment/International Trade Data System (January 19, 2006, 71 FR 3109) for the collection and dissemination of international commercial information.
Eliminating the system of records notice DOT/ALL 18, International Freight Data System, will have no adverse impacts on individuals and will
Privacy Office, Office of the Secretary of Transportation, DOT.
Notice of Privacy Act system of records.
In accordance with the Privacy Act of 1974, the U.S. Department of Transportation proposes to rename, update, and reissue the Department of Transportation system of records currently titled, “Department of Transportation/ALL 8 Employee Transportation Facilitation System of Records.” This system of records allows the Department of Transportation/Office of the Secretary to collect and maintain records on Department of Transportation employees who participate in the Department's transit, carpool/vanpool, bicycle and parking benefit program, employees of other Federal agencies for whom DOT administers a Federal carpool/vanpool, and/or parking and transit benefit program. It also allows the Federal Aviation Administration to collect and maintain records on behalf of its employees who participate in transit and parking benefit programs administered by the Federal Aviation Administration. In addition to non-substantive changes to simply the formatting and text of the previously published notice, we are revising this notice to reflect System Manager's address change, and clarify the routine uses of information in the system. This updated system will be renamed and included in the Department of Transportation's inventory of record systems and referred to as “DOT/ALL 8—Parking and Transit Benefit System.”
Written comments should be submitted on or before November 23, 2015. The Department may publish an amended SORN in light of any comments received. This revised system will be effective November 23, 2015.
You may submit comments, identified by docket number DOT-OST-2015-0160 by any of the following methods:
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For questions, please contact: Claire W. Barrett, Departmental Chief Privacy Officer, Privacy Office, Department of Transportation, Washington, DC 20590;
The DOT/Office of the Secretary (OST) manages a Transportation Subsidy Program (TSP) and facilitates the distribution of public-transport fare media to DOT and other Federal Agency employees, to schedule distribution of the fare media, to maintain an inventory of fare media on hand, and to manage the fare media billing. DOT administers the TSP for its employees, and, also, for employees of other Federal agencies through Interagency Agreements between DOT and the employer-agency. Additionally, the Office of Transportation Services (TRANServe), within DOT's Office of the Assistant Secretary for Administration, manages the bicycle benefit program and the vehicle parking resources at the DOT South East Federal Center (SEFC) Headquarters Facility. Parking at the Headquarters Facility is allocated via the DOT Headquarters Parking Application (DOT HPA) reservation system. The Federal Aviation Administration (FAA) administers its own parking and transit benefit program for FAA employees in the Washington, DC area (transit and parking benefits for FAA field office employees are administered by OST).
In accordance with the Privacy Act of 1974, 5 U.S.C. 552a, the U.S. Department of Transportation (DOT)/Office of the Secretary of Transportation (OST) proposes to rename, update, and reissue the DOT system of records currently titled, “DOT/ALL-8 Employee Transportation Facilitation.” This system of records will be renamed “DOT/ALL-8, Parking and Transit Benefit System.”
In addition, we are updating this system of records notice to reflect the change in the system manager's address resulting from DOT's move from its previous headquarters location at 400 7th Street SW., Washington, DC 20950, to its new location of 1200 New Jersey Ave. SE., Washington, DC 20590. We have also updated the system to provide greater detail about the categories of records collected and maintained, and include additional categories to reflect DOT's administration of the bicycle benefit program. Additionally, DOT will begin to collect the names of other riders in van pools (in addition to those individuals who are participating in the TSP). DOT will collect this information to aid in efforts to identify potential waste, fraud, and abuse. Finally, we are updating the routine uses to provide greater clarity and specificity to our routine uses of the information in this system. The current SORN generally describes the routine uses for this system in a narrative format. We wish to update this to provide great specificity about who we disclose these records to and the purposes for which we make the disclosure. We believe that these changes do not substantively alter the current routine uses, but merely provide greater transparency.
This updated system will be included in DOT's inventory of record systems.
The Privacy Act (5 U.S.C. 552a) governs the means by which the Federal Government collects, maintains, and uses personally identifiable information (PII) in a System of Records. A “System of Records” is a group of any records under the control of a Federal agency from which information about individuals is retrieved by name or other personal identifier. The Privacy
In accordance with 5 U.S.C. 552a(r), DOT has provided a report of this system of records to the Office of Management and Budget and to Congress.
DOT/ALL 8
Parking and Transit Benefit System.
Unclassified, sensitive.
Department of Transportation, Office of the Secretary, Parking and Transit Benefit Office, 1200 New Jersey Ave. SE., Washington, DC 20950; Federal Aviation Administration, Transit Benefit Office, 800 Independence Ave. SW., Washington, DC 20591.
Federal employees' who receive transit or bicycle subsidies, who hold parking permits, or are members of carpools and vanpools; applicants for ridesharing information; recipients of match letters for carpooling; applicants for transit subsidies issued by DOT; vanpool operators.
Categories of records in the system include:
The following information about recipients of bicycle or transit subsidies; holders of parking permits, participants in carpools or vanpools; or applicants for ridesharing information:
Full name
Employee identification number (which, depending on the employer, may be the employee's social security number, the last four digits of the employee's social security number, or some other identification number used by a Federal agency as an employee's identification number)
Employer name
Employer's address
Home address
Business telephone number
Employee's work email address
Transit provider name, address, and mode of transportation used for commute
Location employee commutes to/from
Number of days employee commutes per month
Subsidy amount
System identifier (number randomly generated by DOT's system and assigned to files)
Transit card number
Parking permit number
License plate number and issuing state
Parking permit holder payment status (paid/unpaid) and payment information
Bicycle benefit recipients' itemized lists of expenditures eligible for bicycle benefit
The following information may be collected and maintained about van pool operators:
Full name
Business address
First and last name of individuals who use the van pool
5 U.S.C. 7905; 26 U.S.C. 132; 26 CFR 132f; Executive Order 13150 (April 21, 2001)
The purpose of this system is to collect and maintain information about Federal employees' and vanpool operators who participate in carpool/vanpool, transit, parking, or bicycle benefit programs in connection with the DOT's administration of these programs for its and other Federal agency employees.
In addition to those disclosures generally permitted under 5 U.S.C. 552a(b) of the Privacy Act, all or a portion of the records or information contained in this system may be disclosed outside DOT as a routine use pursuant to 5 U.S.C. 552a(b)(3) as follows:
1. To the Federal agency for whom DOT administers a transit benefit program, for purposes of verifying that agency's employee's participation in the program, and auditing and verifying disbursements;
2. To the operators of transit systems or vanpools for purposes of activating, distributing, and verifying benefits;
3. To the entity that manages the parking facility at the DOT Headquarters in Southeast Washington, DC, information about individuals who have delinquent daily parking fees for purpose of ensuring eligibility of daily parkers;
4. To the Department of Treasury's approved Financial Agent for purposes of distributing transit benefits;
5. To consumer reporting agencies (collecting on behalf of the United States Government) as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f)) or the Federal Claims Collection Act of 1982 (31 U.S.C. 3701(a)(3));
6. See “Prefatory Statement of General Routine Uses” (available at
Disclosures may be made from this system to consumer reporting agencies (collecting on behalf of the United States Government) as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f)) or the Federal Claims Collection Act of 1982 (31 U.S.C. 3701(a)(3)).
Hard copy or electronically. Hard copies are maintained at the System Manager address.
Records can be retrieved by employer agency name, participant name, or any other identifier in the system
Records in this system are safeguarded in accordance with applicable rules and policies, including all applicable DOT automated systems security and access policies. Appropriate controls have been imposed to minimize the risk of compromising the information that is being stored. Access to records in this system is limited to those individuals who have a need to know the information for the performance of their official duties and who have appropriate permissions.
Records in this system are retained for three years and then destroyed, in
OST Parking and Transit Office, 1200 New Jersey Ave. SE., Washington, DC 20950; FAA Transit Benefit Office, 800 Independence Ave. SW., Washington, DC 20591.
Individuals seeking notification of and access to any record contained in this system of records, or seeking to contest its content, may submit a request in writing to the OST Parking and Transit Office at the contact information provided under “System Manager and Address.” FAA employees in the National Capital Region seeking notification of and access to any record contained in this system, or seeking to contest its content, may submit a request in writing to the FAA Transit Benefit Office at the contact information provided under “System Manager and Address.”
When seeking records about yourself from this system of records or any other Departmental system of records your request must conform with the Privacy Act regulations set forth in 49 CFR part 10. You must sign your request, and your signature must either be notarized or submitted under 28 U.S.C. 1746, a law that permits statements to be made under penalty of perjury as a substitute for notarization. While no specific form is required, you may obtain forms for this purpose from the Departmental Freedom of Information Act Officer,
• An explanation of why you believe the Department would have information on you;
• Identify which component(s) of the Department you believe may have the information about you;
• Specify when you believe the records would have been created;
• Provide any other information that will help the FOIA staff determine which DOT component agency may have responsive records; and
If your request is seeking records pertaining to another living individual, you must include a statement from that individual certifying his/her agreement for you to access his/her records. Without this bulleted information the component(s) may not be able to conduct an effective search, and your request may be denied due to lack of specificity or lack of compliance with applicable regulations.
See “Notification procedure” above.
See “Notification procedure” above.
Records are obtain from applications submitted by individuals for parking permits, carpool and vanpool membership, ridesharing information, and fare subsidies; from notifications from other Federal agencies in the program; and from periodic certifications or recertifications and reports regarding fare subsidies.
None.
Electronic applications must be received by 5:00 p.m. ET on December 16, 2015. Applications sent by mail, facsimile or other form will not be accepted. Please note the Community Development Financial Institutions Fund (CDFI Fund) will only accept applications and attachments (
In this NOAA, the CDFI Fund specifically addresses how a CDE may apply to receive an allocation of NMTCs, the competitive procedure through which NMTC allocations will be made, and the actions that will be taken to ensure that proper allocations are made to appropriate entities.
A.
1. As a condition of eligibility for this Allocation Round, the Applicant will not be permitted the use of the proceeds of Qualified Equity Investments (QEIs) to make Qualified Low-Income Community Investments (QLICIs) in Qualified Active Low-Income Community Businesses (QALICBs) where QLICI proceeds are used to repay or refinance any debt or equity provider or a party related to any debt or equity provider whose capital was used to fund the QEI except if: (i) The QLICI proceeds are used to repay documented reasonable expenditures that are directly attributable to the qualified business of the QALICB, and such past expenditures were incurred no more than 24 months prior to the QLICI closing date; or (ii) no more than five percent of the QLICI proceeds are used to repay or refinance prior investment in the QALICB. Refinance includes transferring cash or property directly to
2.
B.
A.
B.
C.
A.
1.
The CDFI Fund will not provide NMTC allocation authority to Applicants that are not certified as CDEs or to entities that are certified as Subsidiary CDEs.
If an Applicant that has already been certified as a CDE wishes to change its designated CDE Service Area, it must submit its request for such change to the CDFI Fund, and the request must be received by the CDFI Fund by 5:00 p.m. ET on November 6, 2015. A request to change a CDE's Service Area must be submitted through the CDFI Fund's Awards Management Information System (AMIS) as a Service Request. Such requests will need to include, at a minimum, the applicable CDE control number, the revised service area designation, and updated accountability information that demonstrates that the CDE has the required representation from Low-Income Communities in the revised Service Area.
2. As a condition of eligibility for this Allocation Round, the Applicant will not be permitted the use of the proceeds of Qualified Equity Investments (QEIs) to make Qualified Low-Income Community Investments (QLICIs) in Qualified Active Low-Income Community Businesses (QALICBs) where QLICI proceeds are used to repay or refinance any debt or equity provider or a party related to any debt or equity provider whose capital was used to fund the QEI except if: (i) The QLICI proceeds are used to repay documented reasonable expenditures that are directly attributable to the qualified business of the QALICB, and such past expenditures were incurred no more than 24 months prior to the QLICI closing date; or (ii) no more than five percent of the QLICI proceeds are used to repay or refinance prior investment in the QALICB. Refinance includes transferring cash or property directly to any debt or equity provider or indirectly to a party related to any debt or equity provider.
3.
(a)
An Allocatee in the CY 2010 allocation round of the NMTC Program is not eligible to receive a NMTC allocation pursuant to this NOAA unless the Allocatee is able to affirmatively demonstrate that, as of 11:59 p.m. ET on January 29, 2016, it has finalized at least 95 percent of its
An Allocatee in the CY 2011 allocation round of the NMTC Program is not eligible to receive a NMTC allocation pursuant to this NOAA unless the Allocatee is able to affirmatively demonstrate that, as of 11:59 p.m. ET on January 29, 2016, it has: (i) Finalized at least 80 percent of its QEIs relating to its CY 2011 NMTC allocation; or (ii) it has finalized at least 70 percent of its QEIs and that at least 100 percent of its total CY 2011 NMTC allocation has been finalized, or has been committed by its investors.
An Allocatee in the CY 2012 allocation round of the NMTC Program is not eligible to receive a NMTC allocation pursuant to this NOAA unless the Allocatee is able to affirmatively demonstrate that, as of 11:59 p.m. ET on January 29, 2016, it has: (i) Finalized at least 70 percent of its QEIs relating to its CY 2012 NMTC allocation; or (ii) it has finalized at least 60 percent of its QEIs and that at least 80 percent of its total CY 2012 NMTC allocation has been finalized, or has been committed by its investors.
An Allocatee (with the exception of a Rural CDE Allocatee) in the CY 2013 allocation round of the NMTC Program is not eligible to receive a NMTC allocation pursuant to this NOAA unless the Allocatee is able to affirmatively demonstrate that, as of 11:59 p.m. ET on January 29, 2016, it has: (i) Finalized at least 50 percent of its QEIs relating to its CY 2013 NMTC allocation; or (ii) it has finalized at least 40 percent of its QEIs and that at least 60 percent of its total CY 2013 NMTC allocation has been finalized, or has been committed by its investors. A prior Rural CDE Allocatee in the CY 2013 is not eligible to receive a NMTC allocation pursuant to this NOAA unless the Allocatee can demonstrate that, as of 11:59 p.m. ET on January 29, 2016, it has finalized at least 30 percent of its CY 2013 NMTC Allocation.
An Allocatee (with the exception of a Rural CDE Allocatee) in the CY 2014 allocation round of the NMTC Program is not eligible to receive a NMTC allocation pursuant to this NOAA unless the Allocatee is able to affirmatively demonstrate that, as of 11:59 p.m. ET on January 29, 2016, it has: (i) Finalized at least 30 percent of its QEIs relating to its CY 2014 NMTC allocation; or (ii) finalized at least 20 percent of its QEIs and that at least 50 percent of its total CY 2014 NMTC allocation has been finalized, or has been committed by its investors. A Rural CDE is not required to meet the above QEI issuance and commitment thresholds with regard to its CY 2014 NMTC allocation award.
Alternatively, an Applicant that has received multiple NMTC allocations between CY 2010 and CY 2014 can also meet the QEI issuance requirements on a cumulative basis. If an Applicant has received multiple NMTC allocation awards between CY 2010 and CY 2014, the Applicant shall be deemed to be eligible to apply for a NMTC allocation pursuant to this NOAA if the Applicant is able to affirmatively demonstrate that, as of 11:59 p.m. ET on January 29, 2016, it has finalized at least 90 percent of its QEIs relating to its cumulative allocation amounts from these prior NMTC Program rounds. Rural CDEs that received allocations under the CY 2013 allocation round may choose to exclude such allocations from this cumulative calculation, provided that the Allocatee has finalized at least 20 percent of its QEIs relating to its CY 2013 allocation. Rural CDEs that received allocations under the CY 2014 allocation round may choose to exclude such allocation from this cumulative calculation.
In addition to the requirements described above, an entity is not eligible to receive a NMTC allocation pursuant to this NOAA if an Affiliate of the Applicant is a prior Allocatee and has not met the requirements for the issuance and/or commitment of QEIs as set forth above for the Allocatees in the prior allocation rounds of the NMTC Program.
For purposes of this section of the NOAA, the CDFI Fund will only recognize as “finalized” those QEIs that have been properly reported in the CDFI Fund's Allocation Tracking System (ATS) by the deadlines specified above. Allocatees and their Subsidiary Allocatees, if any, are advised to access ATS to record each QEI that they issue to an investor in exchange for funds in-hand. For purposes of this section of the NOAA, “committed” QEIs are only those Equity Investments that are evidenced by a written, signed document in which an investor: (i) Commits to make a QEI in the Allocatee in a specified amount and on specified terms; (ii) has made an initial disbursement of the investment proceeds to the Allocatee, and such initial disbursement has been recorded in ATS as a QEI; (iii) commits to disburse the remaining investment proceeds to the Allocatee based on specified amounts and payment dates; and (iv) commits to make the final disbursement to the Allocatee no later than January 29, 2018.
The Applicant will be required, upon notification from the CDFI Fund, to submit adequate documentation to substantiate the required issuances of and commitments for QEIs.
Applicants should be aware that these QEI issuance requirements represent the minimum threshold requirements that must be met in order to submit an application for assistance under this NOAA. As stated in Section V.C.1 of this NOAA, the CDFI Fund reserves the right to reject an application and/or adjust award amounts as appropriate based on information obtained during the review process—including an Applicant's track record of raising QEIs and/or deploying its Qualified Low Income Community Investments (QLICIs).
Any prior Allocatees that requires any action by the CDFI Fund (
(b)
Any Applicant or Affiliate that is in default of its previously executed Allocation Agreement is deemed ineligible under this NOAA if: (i) The CDFI Fund has made a determination that such Applicant is in default of a previously executed Allocation Agreement and (ii) the CDFI Fund has provided written notification of such determination to the Applicant. Moreover, any Applicant that is otherwise eligible as of the application deadline must continue to be compliant with its Allocation Agreement(s) after the application deadline, in order for the CDFI Fund to continue evaluating its application. If an Applicant fails to do such, the CDFI Fund will no longer deem the Applicant eligible.
(c)
(d)
For purposes of the calculation of undisbursed award funds for the BEA Program, only awards made to the Applicant (and any Affiliates) three to five calendar years prior to the end of the calendar year of the application deadline of this NOAA are included (“includable BEA awards”). Thus, for purposes of this NOAA, undisbursed BEA Program award funds are the amount of FYs 2010, 2011, 2012 awards that remain undisbursed as of the application deadline of this NOAA.
For purposes of the calculation of undisbursed award funds for the CDFI Program and the NI, only awards made to the Applicant (and any entity that Controls the Applicant, is Controlled by the Applicant or shares common management officials with the Applicant, as determined by the CDFI Fund) two to five calendar years prior to the end of the calendar year of the application deadline of this NOAA are included (“includable CDFI/NI awards”). Thus, for purposes of this NOAA, undisbursed CDFI Program and NI awards are the amount of FYs 2010, 2011, 2012, and 2013 awards that remain undisbursed as of the application deadline of this NOAA.
To calculate total includable BEA/CDFI/NI awards: Amounts that are undisbursed as of the application deadline of this NOAA cannot exceed five percent (5%) of the total includable awards. Please refer to an example of this calculation in the Round Allocation Application Q&A document, available on the CDFI Fund's Web site.
The “undisbursed award funds” calculation does not include: (i) NMTC allocation authority; (ii) any award funds for which the CDFI Fund received a full and complete disbursement request from the award recipient by the applicable application deadline of this NOAA; (iii) any award funds for an award that has been terminated, in writing, by the CDFI Fund or de-obligated by the CDFI Fund; or (iv) any award funds for an award that does not have a fully executed assistance or award agreement. The CDFI Fund strongly encourages Applicants requesting disbursements of “undisbursed funds” from prior awards to provide the CDFI Fund with a complete disbursement request at least 30 business days prior to the application deadline of this NOAA.
(e)
The CDFI Fund will respond to Applicants' reporting, compliance or disbursement questions between the hours of 9:00 a.m. and 5:00 p.m. ET, starting the date of publication of this NOAA through December 14, 2015 (two days before the application deadline). The CDFI Fund will not respond to Applicants' reporting, compliance, CDE certification, or disbursement phone calls or email inquiries that are received after 5:00 p.m. ET on December 14, 2015 until after the funding application deadline of December 16, 2015.
4.
5.
An Applicant wishing to transfer all or a portion of its NMTC allocation to a Subsidiary is not required to create the Subsidiary prior to submitting a NMTC allocation application to the CDFI Fund. However, the Subsidiary entities must be certified as CDEs by the CDFI Fund, and enjoined as parties to the Allocation Agreement at closing or by amendment to the Allocation Agreement after closing. Before the NMTC allocation transfer may occur it must be pre-approved by the CDFI Fund, in its sole discretion.
The CDFI Fund strongly encourages a non-profit Applicant to submit a CDE certification application to the CDFI Fund on behalf of at least one Subsidiary within 60 days after the non-profit Applicant receives the Notice of Allocation (NOA) from the CDFI Fund, as such Subsidiary must be certified as a CDE prior to entering into an Allocation Agreement with the CDFI Fund. A non-profit Applicant that does not already have a certified for-profit Subsidiary and that fails to submit a certification application for one or more for-profit Subsidiaries within 60 days of the date of the NOA from the CDFI Fund is subject to the CDFI Fund rescinding the award.
6.
(a) As part of the allocation application review process, the CDFI Fund will evaluate whether Applicants are Affiliates, as such term is defined in the allocation application. If an Applicant and its Affiliate(s) wish to submit allocation applications, they must do so collectively, in one application; an Applicant and its Affiliate(s) may not submit separate allocation applications. If Affiliated entities submit multiple applications, the CDFI Fund will reject all such applications received, except for those State-owned or State-controlled governmental Affiliated entities. In the case of State-owned or State-controlled governmental entities, the CDFI Fund may accept applications submitted by different government bodies within the same State, but only to the extent the CDFI Fund determines that the business strategies and/or activities described in such applications, submitted by separate entities, are distinctly dissimilar and/or are operated and/or managed by distinctly dissimilar personnel, including staff, board members or identified consultants. If the CDFI Fund determines that the applications submitted by different government bodies in the same State are not distinctly dissimilar and/or operated and/or managed by distinctly dissimilar personnel, it will reject all such applications. In such cases, the CDFI Fund reserves the right to limit award amounts to such entities to ensure that the entities do not collectively receive more than the $125 million cap.
(b) For purposes of this NOAA, the CDFI Fund will also evaluate whether each Applicant is operated or managed as a “common enterprise” with another Applicant in this Allocation Round using the following indicia, among others: (i) Whether different Applicants have the same individual(s), including the Authorized Representative, staff, board members and/or consultants, involved in day-to-day management, operations and/or investment responsibilities; (ii) whether the Applicants have business strategies and/or proposed activities that are so similar or so closely related that, in fact or effect, they may be viewed as a single entity; and/or (iii) whether the applications submitted by separate Applicants contain significant narrative, textual or other similarities such that they may, in fact or effect, be viewed as substantially identical applications. In such cases, the CDFI Fund will reject all applications received from such entities.
(c) Furthermore, an Applicant that receives an allocation in this Allocation Round (or its Subsidiary Allocatee) may not become an Affiliate of or member of a common enterprise (as defined above) with another Applicant that receives an allocation in this Allocation Round (or its Subsidiary Allocatee) at any time after the submission of an allocation application under this NOAA. This prohibition, however, generally does not apply to entities that are commonly Controlled solely because of common ownership by QEI investors. This requirement will also be a term and condition of the Allocation Agreement (see Section VI.B of this NOAA and additional application guidance materials on the CDFI Fund's Web site at
7.
8.
A.
B.
An Applicant may not submit more than one application in response to this NOAA. In addition, as stated in Section III.A.6 of this NOAA, an Applicant and its Affiliates must collectively submit only one allocation application; an Applicant and its Affiliates may not submit separate allocation applications except as outlined in Section III.A.6 above. Once an application is submitted, an Applicant will not be allowed to change any element of its application.
C.
1.
D.
1.
(a)
E.
F.
G.
A.
In Phase 1, three reviewers will evaluate and score the Business Strategy and Community Outcomes sections of each application. An Applicant must exceed a minimum overall aggregate base score threshold
B.
1.
(a) When assessing an Applicant's business strategy, reviewers will consider, among other things: The Applicant's products, services and investment criteria; the prior performance of the Applicant or its Controlling Entity, particularly as it relates to making similar kinds of investments as those it proposes to make with the proceeds of QEIs; the Applicant's prior performance in providing capital or technical assistance to disadvantaged businesses or communities; the projected level of the Applicant's pipeline of potential investments; the extent to which the Applicant intends to make QLICIs in one or more businesses in which persons unrelated to the entity hold a majority equity interest; and the extent to which Applicants that otherwise have notable relationships with the Qualified Active Low Income Community Businesses (QALICBs) financed will create benefits (beyond those created in the normal course of a NMTC transaction) to Low-Income Communities.
Under the Business Strategy criterion, an Applicant will generally score well to the extent that it will deploy debt or investment capital in products or services which are flexible or non-traditional in form and on better terms than available in the marketplace. An Applicant will also score well to the extent that, among other things: (i) It has a track record of successfully deploying loans or equity investments and providing services similar to those it intends to provide with the proceeds of QEIs; (ii) it has identified a set of clearly-defined potential borrowers or investees; (iii) its projected dollar volume of NMTC deployment is supported by its track record of deployment; (iv) in the case of an Applicant proposing to purchase loans from CDEs, the Applicant will require the CDE selling such loans to re-invest the proceeds of the loan sale to provide additional products and services to Low-Income Communities.
(b)
2.
An Applicant will generally score well under this section to the extent that, among other things: (a) It has a track record of producing quantitative and qualitative community outcomes that are similar to those projected to be achieved with an NMTC allocation; (b) it is working in particularly economically distressed or otherwise underserved communities; (c) its activities are part of a broader community or economic development strategy; (d) it demonstrates a track record of community engagement around past investment decisions; (e) it ensures that an NMTC investment into a project or business is supported by and will be beneficial to Low-Income Persons and residents of Low-Income Communities (LICs); and (f) it is likely to engage in activities that will spur additional private capital investment.
C.
1.
(a).
(b).
(c).
The CDFI Fund will award allocations in the order of the “Final Rank Score,” subject to Applicants meeting all other eligibility requirements; provided, however, that the CDFI Fund, in its sole discretion, reserves the right to reject an application and/or adjust award amounts as appropriate based on information obtained during the review process.
2.
An Applicant will be generally evaluated more favorably under this section to the extent that its management team or other essential personnel have experience in: (a) Deploying capital or technical assistance in Low-Income Communities, particularly those likely to be served by the Applicant with the proceeds of QEIs; (b) asset and risk management; and (c) fulfilling government compliance requirements, particularly tax credit program compliance. An Applicant will also be evaluated favorably to the extent it demonstrates strong financial health and a high likelihood of remaining a going-concern; it clearly explains levels of income and expenses; has policies and systems in place to ensure ongoing compliance with NMTC Program requirements; and, if it is a Federally-insured financial institution, its most recent Community Reinvestment Act (CRA) rating was “outstanding.”
3.
An Applicant will be evaluated more favorably under this section to the extent that: (a) It or its Controlling Entity demonstrate a track record of raising investment capital; (b) it has secured investor commitments, or has a reasonable strategy for obtaining such commitments, or, if it or its Affiliates is a prior Allocatee with a track record in the past five years of raising Qualified Equity Investments or; (c) it generally demonstrates that the economic benefits of the tax credit will be passed through to a QALICB; and (d) it intends to invest the proceeds from the aggregate amount of its QEIs at a level that exceeds the requirements of IRC § 45D(b)(1)(B) and the IRS regulations. In the case of an Applicant proposing to raise investor funds from organizations that also will identify or originate transactions for the Applicant or from Affiliated entities, said Applicant will be evaluated more favorably to the extent that it will offer products with more favorable rates or terms than those currently offered by its investor(s) or Affiliated entities and/or will target its activities to areas of greater economic distress than those currently targeted by the investor or Affiliated entities.
D.
Applicants that meet the minimum scoring thresholds will be advanced to Phase 2 review and will be provided with “preliminary” awards, in descending order of Final Rank Score, until the available allocation authority is fulfilled. Once these “preliminary” award amounts are determined, the CDFI Fund will then analyze the Allocatee pool to determine whether the two Non-Metropolitan proportionality objectives have been met.
The CDFI Fund will first examine the “preliminary” awards and Allocatees to determine whether the percentage of Allocatees that are Rural CDEs is, at a minimum, equal to the percentage of Applicants in the highly qualified pool that are Rural CDEs. If this objective is not achieved, the CDFI Fund will provide awards to additional Rural CDEs from the highly qualified pool, in descending order of their Final Rank Score, until the appropriate percentage balance is achieved. In order to accommodate the additional Rural CDEs in the Allocatee pool within the available allocation limitations, a formula reduction will be applied as uniformly as possible to the allocation amount for all Allocatees in the pool that have not committed to investing a minimum of 20 percent of their QLICIs in Non-Metropolitan counties.
The CDFI Fund will then determine whether the pool of Allocatees will, in the aggregate, invest at least 20 percent of their QLICIs (as measured by dollar amount) in Non-Metropolitan counties. The CDFI Fund will first apply the “minimum” percentage of QLICIs that Allocatees indicated in their applications would be targeted to Non-Metropolitan areas to the total allocation award amount of each Allocatee (less whatever percentage the Allocatee indicated would be retained for non-QLICI activities), and total these figures for all Allocatees. If this aggregate total is greater than or equal to 20 percent of the QLICIs to be made by the Allocatees, then the pool is considered balanced and the CDFI Fund will proceed with the allocation process. However, if the aggregate total is less than 20 percent of the QLICIs to be made by the Allocatees, the CDFI Fund will consider requiring any or all of the Allocatees to direct up to the “maximum” percentage of QLICIs that the Allocatees indicated would be targeted to Non-Metropolitan counties, taking into consideration their track record and ability to deploy dollars in Non-Metropolitan counties. If the CDFI Fund cannot meet the goal of 20 percent of QLICIs in Non-Metropolitan counties by requiring any or all Allocatees to
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F.
The CDFI Fund reserves the right to reject any NMTC allocation application in the case of a prior Allocatee, if such Applicant has failed to use its prior NMTC allocation(s) in a manner that is generally consistent with the business strategy (including, but not limited to, the proposed product offerings, QALICB type, and markets served) set forth in the allocation application(s) related to such prior allocation(s) or such Applicant has been found by the IRS to have engaged in a transaction or series of transactions designed to achieve a result that is inconsistent with the purposes of IRC § 45D. The CDFI Fund also reserves the right to reject any NMTC allocation application in the case of an Affiliate of the Applicant that is a prior Allocatee and has failed to use its prior NMTC allocation(s) in a manner that is generally consistent with the business strategy set forth in the allocation application(s) related to such prior allocation(s) or has been found by the IRS to have engaged in a transaction or series of transactions designed to achieve a result that is inconsistent with the purposes of IRC § 45D.
The CDFI Fund reserves the right to reject an NMTC allocation application if information (including administrative errors or omission of information) 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, adversely affects the CDFI Fund's prior determinations of CDE certification, or indicates fraud or mismanagement on the part of an Applicant or the Controlling Entity, if such fraud or mismanagement by the Controlling Entity would hinder the Applicant's ability to perform under the Allocation Agreement. 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.
As a part of the substantive review process, the CDFI Fund may permit the Allocation Recommendation Panel member(s) to request information from Applicants for the sole purpose of obtaining, clarifying or confirming application information or omission of information. In no event shall such contact be construed to permit an Applicant to change any element of its application. At this point in the process, an Applicant may be required to submit additional information about its application in order to assist the CDFI Fund with its final evaluation process. If the Applicant (or the Controlling Entity or any Affiliate) has previously been awarded an NMTC allocation, the CDFI Fund may also request information on the use of those NMTC allocations, to the extent that this information has not already been reported to the CDFI Fund. Such requests must be responded to within the time parameters set by the CDFI Fund. The selecting official(s) will make a final allocation determination based on an Applicant's file, including, without limitation, eligibility under IRC§ 45D, the reviewers' scores and the amount of allocation authority available.
In the case of Applicants (or the Controlling Entity, or Affiliates) that are regulated or receive oversight by the Federal government or a State agency (or comparable entity), the CDFI Fund may request additional information from the Applicant regarding Assurances and Certifications or other information about the ability of the Applicant to effectively perform under the Allocation Agreement. The Allocation Recommendation Panel or selecting official(s) reserve(s) the right to consult with and take into consideration the views of the appropriate Federal or State banking and other regulatory agencies. The CDFI Fund reserves the right to reject any NMTC Allocation Application if additional information is obtained that, after further due diligence and in the discretion of the CDFI Fund, would hinder the Applicant's ability to effectively perform under the Allocation Agreement. In the case of Applicants (or Affiliates of Applicants) that are also Small Business Investment Companies, Specialized Small Business Investment Companies or New Markets Venture Capital Companies, the CDFI Fund reserves the right to consult with and take into consideration the views of the Small Business Administration.
The CDFI Fund reserves the right to conduct additional due diligence, as determined reasonable and appropriate by the CDFI Fund, in its sole discretion, related to the Applicant, Affiliates, the Applicant's Controlling Entity and the officers, directors, owners, partners and key employees of each. This includes the right to consult with the IRS if the Applicant (or the Controlling Entity, or Affiliates) has previously been awarded an NMTC allocation.
Each Applicant will be informed of the CDFI Fund's award decision through an electronic notification whether selected for an allocation or not selected for an allocation, which may be for reasons of application incompleteness, ineligibility or substantive issues. All Applicants that are not selected for an allocation based on substantive issues will likely be given the opportunity to receive feedback on their applications. This feedback will be provided in a format and within a timeframe to be determined by the CDFI Fund, based on available resources.
The CDFI Fund further 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
There is no right to appeal the CDFI Fund's NMTC allocation decisions. The CDFI Fund's NMTC allocation decisions are final.
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In addition to entering into an Allocation Agreement, each Applicant selected to receive a NMTC allocation must furnish to the CDFI Fund an opinion from its legal counsel or a similar certification, the content of which will be further specified in the Allocation Agreement, to include, among other matters, an opinion that an Applicant (and its Subsidiary Allocatees, if any): (i) Is duly formed and in good standing in the jurisdiction in which it was formed and the jurisdiction(s) in which it operates; (ii) has the authority to enter into the Allocation Agreement and undertake the activities that are specified therein;
If an Allocatee identifies Subsidiary Allocatees, the CDFI Fund reserves the right to require an Allocatee to provide supporting documentation evidencing that it Controls such entities prior to entering into an Allocation Agreement with the Allocatee and its Subsidiary Allocatees. The CDFI Fund reserves the right, in its sole discretion, to rescind its allocation award if the Allocatee fails to return the Allocation Agreement, signed by the authorized representative of the Allocatee, and/or provide the CDFI Fund with any other requested documentation, including an approved legal opinion, within the deadlines set by the CDFI Fund.
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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 due notice to Allocatees.
The CDFI Fund will provide programmatic and information technology support related to the allocation application between the hours of 9:00 a.m. and 5:00 p.m. ET through December 14, 2015. The CDFI Fund will not respond to phone calls or emails concerning the application that are received after 5:00 p.m. ET on December 14, 2015 until after the allocation application deadline of December 16, 2015. Applications and other information regarding the CDFI Fund and its programs may be obtained from the CDFI Fund's Web site at
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In connection with this NOAA, the CDFI Fund may conduct one or more information sessions that will be produced in Washington, DC and broadcast over the internet via webcasting as well as telephone conference calls. For further information on these upcoming information sessions, please visit the CDFI Fund's Web site at
26 U.S.C. 45D; 31 U.S.C. 321; 26 CFR 1.45D-1.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Revenue Procedure 2011-4 (Letter Rulings), Revenue Procedure 2011-5 (Technical Advice), Revenue Procedure 2011-6 (Determination Letters), and Revenue Procedure 2011-8 (User Fees).
Written comments should be received on or before December 22, 2015 to be assured of consideration.
Direct all written comments to Elaine Christophe, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the revenue procedures should be directed to Allan Hopkins, at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet, at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Notice 2009-31, Election and Notice Procedures for Multiemployer Plans under Sections 204 and 205 of WRERA and Revenue Procedure 2009-43, Revocation of Elections by Multiemployer Plans to Freeze Funded Status under section 204 of WRERA.
Written comments should be received on or before December 22, 2015 to be assured of consideration.
Direct all written comments to Elaine Christophe, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of notice should be directed to Allan Hopkins, at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the internet, at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13(44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 5498-QA, ABLE Account Contribution Information, and Form 1099-QA, Distributions from ABLE Accounts.
Written comments should be received on or before December 22, 2015 to be assured of consideration.
Direct all written comments to Elaine Christophe, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Allan Hopkins, at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the internet, at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Request for Comments: Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or 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.
Departmental Offices, Department of the Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the Office of Investment Security, within the Department of the Treasury, is soliciting comments concerning the information collection provisions of the Regulations Pertaining to Mergers, Acquisitions and Takeovers by Foreign Persons, 31 CFR 800.402.
Written comments must be received on or before December 22, 2015 to be assured of consideration.
Direct all written comments to Stephen Hanson, Director, Office of Investment Security, Department of the Treasury, 1500 Pennsylvania Avenue NW., Room 5221, Washington, DC 20220;
Requests for additional information should be directed to Justin Huff, Office of Investment Security, Department of the Treasury, 1500 Pennsylvania Avenue NW., Washington, DC 20220; (202) 622-6133.
Reason for change: There is an adjustment in the number of respondents from 105 to 130.
Department of the Treasury.
Notice of availability; request for comments.
The Board of Trustees of the Central States, Southeast and Southwest Areas Pension Plan (Central States Pension Plan), a multiemployer pension plan, has submitted an application to Treasury to reduce benefits under the Central States Pension Plan in accordance with the Multiemployer Pension Reform Act of 2014 (MPRA). The purpose of this notice is to announce that the application submitted by the Board of Trustees of the Central States Pension Plan has been published on the Treasury Web site, and to request public comments on the application from interested parties, including contributing employers, employee organizations, and participants and beneficiaries of the Central States Pension Plan.
Comments must be received by December 7, 2015.
You may submit comments electronically through the Federal eRulemaking Portal at
Comments may also be mailed to the Department of the Treasury, MPRA Office, 1500 Pennsylvania Avenue NW., Room 1224, Washington, DC 20220. Attn: Deva Kyle. Comments sent via facsimile and email will not be accepted.
For information regarding the application from the Board of Trustees of the Central States Pension Plan, please contact Treasury at (202) 622-1534 (not a toll-free number).
The Multiemployer Pension Reform Act of 2014 (MPRA) amended the Internal Revenue Code to permit a multiemployer plan that is projected to have insufficient funds to reduce pension benefits payable to participants and beneficiaries if certain conditions are satisfied. In order to reduce benefits, the plan sponsor is required to submit an application to the Secretary of the Treasury, which the Department of the Treasury (Treasury), in consultation with the Pension Benefit Guaranty Corporation (PBGC) and the Secretary of Labor, is required to approve or deny.
On September 25, 2015, the Board of Trustees of the Central States Pension Plan submitted an application for approval to reduce benefits under the Central States Pension Plan. As required by the MPRA, that application has been published on Treasury's Web site at
Comments are requested from interested parties, including contributing employers, employee organizations, and participants and beneficiaries of the Central States Pension Plan. Consideration will be given to any comments that are timely received by Treasury.
Environmental Protection Agency (EPA).
Final rule.
The Environmental Protection Agency (EPA) is finalizing new source performance standards (NSPS) under Clean Air Act (CAA) section 111(b) that, for the first time, will establish standards for emissions of carbon dioxide (CO
This final rule is effective on October 23, 2015. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of October 23, 2015.
The EPA has established dockets for this action under Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No. EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units). All documents in the dockets are listed on the
Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-2968, facsimile number (919) 541-5450; email address:
In this final action the EPA is establishing standards that limit greenhouse gas (GHG) emissions from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and stationary combustion turbines, following the issuance of proposals for such standards and an accompanying Notice of Data Availability.
On June 25, 2013, in conjunction with the announcement of his Climate Action Plan (CAP), President Obama issued a
The EPA subsequently issued a Notice of Data Availability (NODA) in which the EPA solicited comment on its initial interpretation of provisions in the Energy Policy Act of 2005 (EPAct05) and associated provisions in the Internal Revenue Code (IRC) and also solicited comment on a companion Technical Support Document (TSD) that addressed these provisions' relationship to the factual record supporting the proposed rule. 79 FR 10750 (February 26, 2014).
On June 2, 2014, the EPA proposed standards of performance, also pursuant to CAA section 111(b), to limit emissions of CO
In this action, the EPA is issuing final standards of performance to limit emissions of GHG pollution manifested as CO
In a separate action that affects the same source category, the EPA is issuing final emission guidelines under CAA section 111(d) for states to use in developing plans to limit CO
The EPA received numerous comments and conducted extensive outreach to stakeholders for this rulemaking. After careful consideration of public comments and input from a variety of stakeholders, the final standards of performance in this action reflect certain changes from the proposals. Comments considered include written comments that were submitted during the public comment period and oral testimony provided during the public hearing for the proposed standards.
The BSER determinations and final standards of performance for affected newly constructed, modified, and reconstructed EGUs are summarized in Table 1 and discussed in more detail below. The final standards for new, modified, and reconstructed EGUs apply to sources that commenced construction—or modification or reconstruction, as appropriate—on or after the date of publication of corresponding proposed standards.
This action establishes
The EPA proposed that the BSER for newly constructed steam generating EGUs was highly efficient new generating technology (
The BSER for newly constructed steam generating EGUs in the final rule is very similar to that in the January 2014 proposal. In this final action, the EPA finds that a highly efficient new supercritical pulverized coal (SCPC) utility boiler EGU implementing partial CCS to the degree necessary to achieve an emission of 1,400 lb CO
The EPA finds that a highly efficient SCPC implementing partial CCS is the BSER because CCS technology has been demonstrated to be technically feasible and is in use or under construction in various industrial sectors, including the power generation sector. For example, the Boundary Dam Unit #3 CCS project in Saskatchewan, Canada is a full-scale, fully integrated CCS project that is currently operating and is designed to capture more than 90 percent of the CO
We note that identifying a highly efficient new SCPC EGU implementing partial CCS as the BSER provides a path forward for new fossil fuel-fired steam generation in the current market context. Numerous studies have predicted that few new fossil fuel-fired steam generating units will be constructed in the future. These analyses identify a range of factors unrelated to this rulemaking, including low electricity demand growth, highly competitive natural gas prices, and increases in the supply of renewable energy. The EPA recognizes that, in certain circumstances, there may be interest in building fossil fuel-fired steam generating units despite these market conditions. In particular, utilities and project developers may build new fossil fuel-fired steam generating EGUs in order to achieve or maintain fuel diversity within generating fleets, as a hedge against the possibility of natural gas prices far exceeding projections, or to co-produce both power and chemicals, including capturing CO
The EPA is also issuing final standards for steam generating units that implement “large modifications,” (
The standards of performance for modified steam generating units that make large modifications are based on each affected unit's own best potential performance as the BSER. Specifically, such a modified steam generating unit will be required to meet a unit-specific CO
The final standards for steam generating units implementing large modifications are similar to the proposed standards for such units. In the proposal, we suggested that the standard should be based on when the modification is undertaken (
The EPA is not promulgating final standards of performance for, and is withdrawing the proposed standards for steam generating sources that make modifications resulting in an increase of hourly CO
For reconstructed steam generating units, the EPA is finalizing standards based on the performance of the most efficient generating technology for these types of units as the BSER (
This action also finalizes standards of performance for newly constructed and reconstructed stationary combustion turbines. In the January 2014 proposal for newly constructed EGUs, the EPA proposed that natural gas-fired stationary combustion turbines (
In the January 2014 proposal for newly constructed combustion turbines, the EPA proposed standards for two subcategories of base load natural gas-fired stationary combustion turbines. The proposed standard for small combustion turbines (units with base load ratings less than or equal to 850 MMBtu/h) was 1,100 lb CO
In the June 2014 proposal for modified and reconstructed combustion turbines, the EPA solicited comment on alternative approaches for establishing applicability and subcategorization criteria, including (1) eliminating the “constructed for the purpose of supplying” qualifier for the total electric sales and percentage electric sales criteria, (2) eliminating the 219,000 MWh total electric sales criterion altogether, (3) replacing the fixed percentage electric sales criterion with a variable percentage electric sales criterion (
In both proposals, the EPA also solicited comment on a broad applicability approach that would include non-base load natural gas-fired units (primarily simple cycle combustion turbines) and multi-fuel-fired units (primarily distillate oil-fired combustion turbines) in the general applicability of subpart TTTT. As part of the broad applicability approach, the EPA solicited comment on imposing “no emission standard” or establishing separate numerical limits for these two subcategories.
In this action, the EPA is finalizing a variation of the approaches put forward in the January 2014 proposal for new sources and the June 2014 proposal for modified and reconstructed sources. Based on our review of public comments related to the proposed subcategories for small and large combustion turbines and our additional data analyses, we have determined that there is no need to set two separate standards for different sizes of combustion turbines for base load natural gas-fired combustion turbines. The EPA has determined that all sizes of affected newly constructed and reconstructed stationary combustion turbines can achieve the final standards. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the EPA is finalizing a standard of 1,000 lb CO
The EPA is eliminating the 219,000 MWh total annual electric sales criterion for non-CHP units. In addition, the EPA is finalizing the sliding-scale approach for deriving the unit-specific, percentage electric sales threshold above which a combustion turbine transitions from the subcategory for non-base load units to the subcategory for base load units. For newly constructed and reconstructed non-base load natural gas-fired stationary combustion turbines, the EPA is finalizing the combustion of clean fuels (natural gas with a small allowance for distillate oil) as the BSER with a corresponding heat input-based standard of 120 lb CO
In addition, for newly constructed and reconstructed multi-fuel-fired stationary combustion turbines, the EPA is finalizing an input-based standard of 120 to 160 lb CO
We are not promulgating final standards of performance for stationary combustion turbines that make modifications at this time. We are simultaneously withdrawing the proposed standards for modifications (see Section XV of this preamble). As we indicated in the proposal, sources from the power sector have notified the EPA of very few NSPS modifications, and we expect that there will be few NSPS modifications for CO
A more detailed discussion of the final standards of performance for stationary combustion turbines, the applicability criteria, and the comments that influenced the final standards is provided in Sections VIII and IX of this preamble.
As explained in the regulatory impact analysis (RIA) for this final rule, available data—including utility announcements and Energy Information Administration (EIA) modeling—indicate that, even in the absence of this rule, (i) existing and anticipated economic conditions are such that few, if any, fossil fuel-fired steam-generating EGUs will be built in the foreseeable future, and (ii) utilities and project developers are expected to choose new generation technologies (primarily NGCC) that would meet the final standards and renewable generating sources that are not affected by these final standards. These projections are consistent with utility announcements and EIA modeling that indicate that new units are likely to be NGCC and that any coal-fired steam generating units built between now and 2030 would have CCS, even in the absence of this rule.
As explained in the RIA and further below, the EPA has been notified of few power sector NSPS modifications or reconstructions. Based on that experience, the EPA expects that few EGUs will trigger either the modification or the reconstruction provisions that we are finalizing in this action. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
The entities potentially affected by the standards are shown in Table 2 below.
This table is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by this action. To determine whether your facility, company, business, organization, etc., would be regulated by this action, refer to Section III of this preamble for more information and examine the applicability criteria in 40 CFR 60.1 (General Provisions) and § 60.550840 of subpart TTTT (Standards of Performance for Greenhouse Gas Emissions for Electric Utility Generating Units). If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).
In addition to being available in the docket, an electronic copy of this final action will also be available on the Worldwide Web (WWW). Following signature, a copy of this final action will be posted at the following address:
Under section 307(b)(1) of the CAA, judicial review of this final rule is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by December 22, 2015. Moreover, under section 307(b)(2) of the CAA, the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce these requirements. Section 307(d)(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism mandating the EPA to convene a proceeding for reconsideration if the person raising an objection can demonstrate that it was impracticable to raise such objection within the period for public comment or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule. Any person seeking to make such a demonstration should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding
This action presents the EPA's final standards of performance for newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and newly constructed and reconstructed stationary combustion turbines. Section II provides background information on climate change impacts from GHG emissions, GHG emissions from fossil fuel-fired EGUs, the utility power sector, the statutory and regulatory background relating to CAA section 111(b), EPA actions prior to this final action, and public comments regarding the proposed actions. Section III explains the EPA's authority to regulate CO
In this section, we discuss climate change impacts from GHG emissions, both on public health and public welfare. We also present information about GHG emissions from fossil fuel-fired EGUs and describe the utility power sector and its changing structure. We then summarize the statutory and regulatory background relevant to this final rulemaking. In addition, we provide background information on the EPA's January 8, 2014 proposed carbon pollution standards for newly constructed fossil fuel-fired EGUs, the June 18, 2014 proposed carbon pollution standards for modified and reconstructed EGUs, and other actions associated with this final rulemaking. We close this section with a general discussion of comments and stakeholder input that the EPA received prior to issuing this final rulemaking.
According to the National Research Council, “Emissions of CO
In 2009, based on a large body of robust and compelling scientific evidence, the EPA Administrator issued the Endangerment Finding under CAA section 202(a)(1).
Climate change caused by human emissions of GHGs threatens the health of Americans in multiple ways. By raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses. While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the United States. Compared to a future without climate change, climate change is expected to increase ozone pollution over broad areas of the U.S., especially on the highest ozone days and in the largest metropolitan areas with the worst ozone problems, and thereby increase the risk of morbidity and mortality. Climate change is also expected to cause more intense hurricanes and more frequent and intense storms and heavy precipitation, with impacts on other areas of public health, such as the potential for increased deaths, injuries, infectious and waterborne diseases, and stress-related disorders. Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects.
Climate change impacts touch nearly every aspect of public welfare. Among the multiple threats caused by human emissions of GHGs, climate changes are expected to place large areas of the country at serious risk of reduced water supplies, increased water pollution, and increased occurrence of extreme events such as floods and droughts. Coastal areas are expected to face a multitude of increased risks, particularly from rising sea level and increases in the severity of storms. These communities face storm and flood damage to property, or even loss of land due to inundation, erosion, wetland submergence and habitat loss.
Impacts of climate change on public welfare also include threats to social and ecosystem services. Climate change is expected to result in an increase in peak electricity demand. Extreme weather from climate change threatens energy, transportation, and water resource infrastructure. Climate change may also exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous communities, and is very likely to fundamentally rearrange U.S. ecosystems over the 21st century. Though some benefits may balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards increasing risks of net adverse impacts on U.S. food production, agriculture and forest productivity as temperature continues to rise. These impacts are global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S.
Since the administrative record concerning the Endangerment Finding closed following the EPA's 2010 Reconsideration Denial, the climate has continued to change, with new records being set for a number of climate indicators such as global average surface temperatures, Arctic sea ice retreat, CO
The EPA has carefully reviewed these recent assessments in keeping with the same approach outlined in Section III.A of the 2009 Endangerment Finding, which was to rely primarily upon the major assessments by the USGCRP, the IPCC, and the NRC of the National Academies to provide the technical and scientific information to inform the Administrator's judgment regarding the question of whether GHGs endanger public health and welfare. These
The findings of the recent scientific assessments confirm and strengthen the conclusion that GHGs endanger public health, now and in the future. The NCA3 indicates that human health in the United States will be impacted by “increased extreme weather events, wildfire, decreased air quality, threats to mental health, and illnesses transmitted by food, water, and disease-carriers such as mosquitoes and ticks.” The most recent assessments now have greater confidence that climate change will influence production of pollen that exacerbates asthma and other allergic respiratory diseases such as allergic rhinitis, as well as effects on conjunctivitis and dermatitis. Both the NCA3 and the IPCC AR5 found that increasing temperature has lengthened the allergenic pollen season for ragweed, and that increased CO
The NCA3 also finds that climate change, in addition to chronic stresses such as extreme poverty, is negatively affecting indigenous peoples' health in the United States through impacts such as reduced access to traditional foods, decreased water quality, and increasing exposure to health and safety hazards. The IPCC AR5 finds that climate change-induced warming in the Arctic and resultant changes in environment (
The NCA3 concludes that children's unique physiology and developing bodies contribute to making them particularly vulnerable to climate change. Impacts on children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. The IPCC AR5 indicates that children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. The IPCC finds that additional health concerns may arise in low-income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
Both the NCA3 and IPCC AR5 conclude that climate change will increase health risks facing the elderly. Older people are at much higher risk of mortality during extreme heat events. Pre-existing health conditions also make older adults susceptible to cardiac and respiratory impacts of air pollution and to more severe consequences from infectious and waterborne diseases. Limited mobility among older adults can also increase health risks associated with extreme weather and floods.
The new assessments also confirm and strengthen the conclusion that GHGs endanger public welfare, and emphasize the urgency of reducing GHG emissions due to their projections that show GHG concentrations climbing to ever-increasing levels in the absence of mitigation. The NRC assessment,
Future temperature changes will depend on what emission path the world follows. In its high emission scenario, the IPCC AR5 projects that
While rainfall may only see small globally and annually averaged changes, there are expected to be substantial shifts in where and when that precipitation falls. According to the NCA3, regions closer to the poles will see more precipitation, while the dry subtropics are expected to expand (colloquially, this has been summarized as wet areas getting wetter and dry regions getting drier). In particular, the NCA3 notes that the western U.S., and especially the Southwest, is expected to become drier. This projection is consistent with the recent observed drought trend in the West. At the time of publication of the NCA, even before the last 2 years of extreme drought in California, tree ring data was already indicating that the region might be experiencing its driest period in 800 years. Similarly, the NCA3 projects that heavy downpours are expected to increase in many regions, with precipitation events in general becoming less frequent but more intense. This trend has already been observed in regions such as the Midwest, Northeast, and upper Great Plains. Meanwhile, the NRC Climate Stabilization Targets assessment found that the area burned by wildfire is expected to grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of warming, the assessment found that 9 out of 10 summers would be warmer than all but the 5 percent of warmest summers today, leading to increased frequency, duration, and intensity of heat waves. Extrapolations by the NCA also indicate that Arctic sea ice in summer may essentially disappear by mid-century. Retreating snow and ice, and emissions of CO
Since the 2009 Endangerment Finding, the USGCRP NCA3, and multiple NRC assessments have projected future rates of sea level rise that are 40 percent larger to more than twice as large as the previous estimates from the 2007 IPCC 4th Assessment Report due in part to improved understanding of the future rate of melt of the Antarctic and Greenland Ice sheets. The NRC
In general, climate change impacts are expected to be unevenly distributed across different regions of the United States and have a greater impact on certain populations, such as indigenous peoples and the poor. The NCA3 finds that climate change impacts such as the rapid pace of temperature rise, coastal erosion and inundation related to sea level rise and storms, ice and snow melt, and permafrost thaw are affecting indigenous people in the U.S. Particularly in Alaska, critical infrastructure and traditional livelihoods are threatened by climate change and, “[i]n parts of Alaska, Louisiana, the Pacific Islands, and other coastal locations, climate change impacts (through erosion and inundation) are so severe that some communities are already relocating from historical homelands to which their traditions and cultural identities are tied.”
CO
Events outside the United States, as also pointed out in the 2009 Endangerment Finding, will also have relevant consequences. The NRC
In addition to future impacts, the NCA3 emphasizes that climate change driven by human emissions of GHGs is already happening now and it is happening in the United States. According to the IPCC AR5 and the NCA3, there are a number of climate-related changes that have been observed recently, and these changes are projected to accelerate in the future. The planet warmed about 0.85 °C (1.5 °F) from 1880 to 2012. It is extremely likely (>95 percent probability) that human influence was the dominant cause of the observed warming since the mid-20th century, and likely (>66 percent probability) that human influence has more than doubled the probability of occurrence of heat waves in some locations. In the Northern Hemisphere, the last 30 years were likely the warmest 30-year period of the last 1400 years. U.S. average temperatures have similarly increased by 1.3 to 1.9 °F since 1895, with most of that increase occurring since 1970. Global sea levels rose 0.19 m (7.5 inches) from 1901 to 2010. Contributing to this rise was the warming of the oceans and melting of land ice. It is likely that 275 gigatons per year of ice have melted from land glaciers (not including ice sheets) since 1993, and that the rate of loss of ice from the Greenland and Antarctic ice sheets has increased substantially in recent years, to 215 gigatons per year and 147 gigatons per year respectively, since 2002. For context, 360 gigatons of ice melt is sufficient to cause global sea levels to rise 1 mm. Annual mean Arctic sea ice has been declining at 3.5 to 4.1 percent per decade, and Northern Hemisphere snow cover extent has decreased at about 1.6 percent per decade for March and 11.7 percent per decade for June. Permafrost temperatures have increased in most regions since the 1980s, by up to 3 °C (5.4 °F) in parts of Northern Alaska. Winter storm frequency and intensity have both increased in the Northern Hemisphere. The NCA3 states that the increases in the severity or frequency of some types of extreme weather and climate events in recent decades can affect energy production and delivery, causing supply disruptions, and compromise other essential infrastructure such as water and transportation systems.
In addition to the changes documented in the assessment literature, there have been other climate milestones of note. In 2009, the year of the Endangerment Finding, the average concentration of CO
These assessments and observed changes make it clear that reducing emissions of GHGs across the globe is necessary in order to avoid the worst impacts of climate change, and underscore the urgency of reducing emissions now. The NRC Committee on America's Climate Choices listed a number of reasons “why it is imprudent to delay actions that at least begin the process of substantially reducing emissions.”
• The faster emissions are reduced, the lower the risks posed by climate change. Delays in reducing emissions could commit the planet to a wide range of adverse impacts, especially if the sensitivity of the climate to greenhouse gases is on the higher end of the estimated range.
• Waiting for unacceptable impacts to occur before taking action is imprudent because the effects of greenhouse gas emissions do not fully manifest themselves for decades and, once manifest, many of these changes will persist for hundreds or even thousands of years.
• In the committee's judgment, the risks associated with doing business as usual are a much greater concern than the risks associated with engaging in strong response efforts.
The NCA3 assessed the climate impacts in eight regions of the United States, noting that changes in physical climate parameters such as temperatures, precipitation, and sea ice retreat were already having impacts on forests, water supplies, ecosystems, flooding, heat waves, and air quality. Moreover, the NCA3 found that future warming is projected to be much larger than recent observed variations in temperature, with precipitation likely to increase in the northern states, decrease in the southern states, and with the heaviest precipitation events projected to increase everywhere.
In the Northeast, temperatures increased almost 2 °F from 1895 to 2011, precipitation increased by about 5 inches (10 percent), and sea level rise of about a foot has led to an increase in coastal flooding. The 70 percent increase in the amount of rainfall falling in the 1 percent of the most intense events is a larger increase in extreme precipitation than experienced in any other U.S. region.
In the future, if emissions continue increasing, the Northeast is expected to experience 4.5 to 10 °F of warming by
In the Southeast, average annual temperature during the last century cycled between warm and cool periods. A warm peak occurred during the 1930s and 1940s, followed by a cool period, and temperatures then increased again from 1970 to the present by an average of 2 °F. There have been increasing numbers of days above 95 °F and nights above 75 °F, and decreasing numbers of extremely cold days since 1970. Daily and five-day rainfall intensities have also increased, and summers have been either increasingly dry or extremely wet. Louisiana has already lost 1,880 square miles of land in the last 80 years due to sea level rise and other contributing factors.
The Southeast is exceptionally vulnerable to sea level rise, extreme heat events, hurricanes, and decreased water availability. Major consequences of further warming include significant increases in the number of hot days (95 °F or above) and decreases in freezing events, as well as exacerbated ground-level ozone in urban areas. Although projected warming for some parts of the region by the year 2100 is generally smaller than for other regions of the United States, projected warming for interior states of the region is larger than coastal regions by 1 °F to 2 °F. Projections further suggest that there will be fewer tropical storms globally, but that they will be more intense, with more Category 4 and 5 storms. The NCA identified New Orleans, Miami, Tampa, Charleston, and Virginia Beach as being specific cities that are at risk due to sea level rise, with homes and infrastructure increasingly prone to flooding. Additional impacts of sea level rise are expected for coastal highways, wetlands, fresh water supplies, and energy infrastructure.
In the Northwest, temperatures increased by about 1.3 °F between 1895 and 2011. A small average increase in precipitation was observed over this time period. However, warming temperatures have caused increased rainfall relative to snowfall, which has altered water availability from snowpack across parts of the region. Snowpack in the Northwest is an important freshwater source for the region. More precipitation falling as rain instead of snow has reduced the snowpack, and warmer springs have corresponded to earlier snowpack melting and reduced streamflows during summer months. Drier conditions have increased the extent of wildfires in the region.
Average annual temperatures are projected to increase by 3.3 °F to 9.7 °F by the end of the century (depending on future global GHG emissions), with the greatest warming expected during the summer. Continued increases in global GHG emissions are projected to result in up to a 30 percent decrease in summer precipitation. Earlier snowpack melt and lower summer stream flows are expected by the end of the century and will affect drinking water supplies, agriculture, ecosystems, and hydropower production. Warmer waters are expected to increase disease and mortality in important fish species, including Chinook and sockeye salmon. Ocean acidification also threatens species such as oysters, with the Northwest coastal waters already being some of the most acidified worldwide due to coastal upwelling and other local factors. Forest pests are expected to spread and wildfires to burn larger areas. Other high-elevation ecosystems are projected to be lost because they can no longer survive the climatic conditions. Low lying coastal areas, including the cities of Seattle and Olympia, will experience heightened risks of sea level rise, erosion, seawater inundation and damage to infrastructure and coastal ecosystems.
In Alaska, temperatures have changed faster than anywhere else in the United States. Annual temperatures increased by about 3 °F in the past 60 years. Warming in the winter has been even greater, rising by an average of 6 °F. Arctic sea ice is thinning and shrinking in area, with the summer minimum ice extent now covering only half the area it did when satellite records began in 1979. Glaciers in Alaska are melting at some of the fastest rates on Earth. Permafrost soils are also warming and beginning to thaw. Drier conditions have contributed to more large wildfires in the last 10 years than in any previous decade since the 1940s, when recordkeeping began. Climate change impacts are harming the health, safety, and livelihoods of Native Alaskan communities.
By the end of this century, continued increases in GHG emissions are expected to increase temperatures by 10 to 12 °F in the northernmost parts of Alaska, by 8 to 10 °F in the interior, and by 6 to 8 °F across the rest of the state. These increases will exacerbate ongoing arctic sea ice loss, glacial melt, permafrost thaw and increased wildfire, and threaten humans, ecosystems, and infrastructure. Precipitation is expected to increase to varying degrees across the state. However, warmer air temperatures and a longer growing season are expected to result in drier conditions. Native Alaskans are expected to experience declines in economically, nutritionally, and culturally important wildlife and plant species. Health threats will also increase, including loss of clean water, saltwater intrusion, sewage contamination from thawing permafrost, and northward extension of diseases. Wildfires will increasingly pose threats to human health as a result of smoke and direct contact. Areas underlain by ice-rich permafrost across the state are likely to experience ground subsidence and extensive damage to infrastructure as the permafrost thaws. Important ecosystems will continue to be affected. Surface waters and wetlands that are drying provide breeding habitat for millions of waterfowl and shorebirds that winter in the lower 48 states. Warmer ocean temperatures, acidification, and declining sea ice will contribute to changes in the location and availability of commercially and culturally important marine fish.
In the Southwest, temperatures are now about 2 °F higher than the past century, and are already the warmest that region has experienced in at least 600 years. The NCA notes that there is evidence that climate change-induced warming on top of recent drought has influenced tree mortality, wildfire frequency and area, and forest insect outbreaks. Sea levels have risen about 7
Projections indicate that the Southwest will warm an additional 5.5 to 9.5 °F over the next century if emissions continue to increase. Winter snowpack in the Southwest is projected to decline (consistent with the record lows from this past winter), reducing the reliability of surface water supplies for cities, agriculture, cooling for power plants, and ecosystems. Sea level rise along the California coast will worsen coastal erosion, increase flooding risk for coastal highways, bridges, and low-lying airports, pose a threat to groundwater supplies in coastal cities such as Los Angeles, and increase vulnerability to floods for hundreds of thousands of residents in coastal areas. Climate change will also have impacts on the high-value specialty crops grown in the region as a drier climate will increase demands for irrigation, more frequent heat waves will reduce yields, and decreased winter chills may impair fruit and nut production for trees in California. Increased drought, higher temperatures, and bark beetle outbreaks are likely to contribute to continued increases in wildfires. The highly urbanized population of the Southwest is vulnerable to heat waves and water supply disruptions, which can be exacerbated in cases where high use of air conditioning triggers energy system failures.
The rate of warming in the Midwest has markedly accelerated over the past few decades. Temperatures rose by more than 1.5 °F from 1900 to 2010, but between 1980 and 2010, the rate of warming was three times faster than from 1900 through 2010. Precipitation generally increased over the last century, with much of the increase driven by intensification of the heaviest rainfalls. Several types of extreme weather events in the Midwest (
In the future, if emissions continue increasing, the Midwest is expected to experience 5.6 to 8.5 °F of warming by the 2080s, leading to more heat waves. Though projections of changes in total precipitation vary across the regions, more precipitation is expected to fall in the form of heavy downpours across the entire region, leading to an increase in flooding. Specific vulnerabilities highlighted by the NCA include long-term decreases in agricultural productivity, changes in the composition of the region's forests, increased public health threats from heat waves and degraded air and water quality, negative impacts on transportation and other infrastructure associated with extreme rainfall events and flooding, and risks to the Great Lakes including shifts in invasive species, increases in harmful algal blooms, and declining beach health.
High temperatures (more than 100 °F in the Southern Plains and more than 95 °F in the Northern Plains) are projected to occur much more frequently by mid-century. Increases in extreme heat will increase heat stress for residents, energy demand for air conditioning, and water losses. North Dakota's increase in annual temperatures over the past 130 years is the fastest in the contiguous U.S., mainly driven by warming winters. Specific vulnerabilities highlighted by the NCA include increased demand for water and energy, changes to crop-growth cycles and agricultural practices, and negative impacts on local plant and animal species from habitat fragmentation, wildfires, and changes in the timing of flowering or pest patterns. Communities that are already the most vulnerable to weather and climate extremes will be stressed even further by more frequent extreme events occurring within an already highly variable climate system.
In Hawaii, other Pacific islands, and the Caribbean, rising air and ocean temperatures, shifting rainfall patterns, changing frequencies and intensities of storms and drought, decreasing baseflow in streams, rising sea levels, and changing ocean chemistry will affect ecosystems on land and in the oceans, as well as local communities, livelihoods, and cultures. Low islands are particularly at risk.
Rising sea levels, coupled with high water levels caused by tropical and extra-tropical storms, will incrementally increase coastal flooding and erosion, damaging coastal ecosystems, infrastructure, and agriculture, and negatively affecting tourism. Ocean temperatures in the Pacific region exhibit strong year-to-year and decadal fluctuations, but since the 1950s, they have exhibited a warming trend, with temperatures from the surface to a depth of 660 feet rising by as much as 3.6 °F. As a result of current sea level rise, the coastline of Puerto Rico around Rincón is being eroded at a rate of 3.3 feet per year. Freshwater supplies are already constrained and will become more limited on many islands. Saltwater intrusion associated with sea level rise will reduce the quantity and quality of freshwater in coastal aquifers, especially on low islands. In areas where precipitation does not increase, freshwater supplies will be adversely affected as air temperature rises.
Warmer oceans are leading to increased coral bleaching events and disease outbreaks in coral reefs, as well as changed distribution patterns of tuna fisheries. Ocean acidification will reduce coral growth and health. Warming and acidification, combined with existing stresses, will strongly affect coral-reef fish communities. For Hawaii and the Pacific islands, future sea surface temperatures are projected to increase 2.3 °F by 2055 and 4.7 °F by 2090 under a scenario that assumes continued increases in emissions. Ocean acidification is also taking place in the region, which adds to ecosystem stress from increasing temperatures. Ocean acidity has increased by about 30 percent since the pre-industrial era and is projected to further increase by 37 percent to 50 percent from present levels by 2100.
The NCA also discussed impacts that occur along the coasts and in the oceans adjacent to many regions, and noted that other impacts occur across regions and landscapes in ways that do not follow political boundaries.
Fossil fuel-fired EGUs are by far the largest emitters of GHGs among stationary sources in the U.S., primarily in the form of CO
The EPA implements a separate program under 40 CFR part 98 called the Greenhouse Gas Reporting Program
The EPA prepares the official U.S. GHG Inventory to comply with commitments under the United Nations Framework Convention on Climate
Total fossil energy-related CO
In addition
It should be noted that the discussion above concerned all fossil fuel-fired EGUs. Steam generators emitted 1,627 MMT CO
The EPA includes a background discussion of the electricity system in the Clean Power Plan (CPP) rulemaking, which is the companion rulemaking to this rule that promulgates emission guidelines for states to use in regulating emissions of CO
The electricity sector is undergoing a period of intense change. Fossil fuels—such as coal, natural gas, and oil—have historically provided a large percentage of electricity in the U.S., with smaller amounts being provided by other types of generation, including nuclear and renewables such as wind, solar, and hydroelectric power. Coal has historically provided the largest percentage of fossil-fuel generation.
The change in the resource mix has accelerated in recent years, but wind, solar, other renewables, and energy-efficiency resources have been reliably participating in the electric sector for a number of years. This rapid development of non-fossil fuel resources is occurring as much of the existing power generation fleet in the U.S. is aging and in need of modernization and replacement.
Natural gas has a long history of meeting electricity demand in the U.S. with a rapidly growing role as domestic supplies of natural gas have dramatically increased. Natural gas net generation increased by approximately 36 percent between 2004 and 2014.
Renewable sources of electric generation also have a history of meeting electricity demand in the U.S. and are expected to have an increasing role going forward. A series of energy crises provided the impetus for renewable energy development in the early 1970s. The OPEC oil embargo in 1973 and oil crisis of 1979 caused oil price spikes, more frequent energy shortages, and significantly affected the national and global economy. In 1978, partly in response to fuel security concerns, Congress passed the Public Utilities Regulatory Policies Act (PURPA) which required local electric utilities to buy power from qualifying facilities (QFs).
Price pressures caused by oil embargoes in the 1970s also brought the issues of conservation and energy efficiency to the forefront of U.S. energy policy.
Advancements and innovation in power sector technologies provide the opportunity to address CO
Natural gas-fired EGUs typically use one of two technologies: NGCC or simple cycle combustion turbines. NGCC units first generate power from a combustion turbine (the combustion cycle). The unused heat from the combustion turbine is then routed to a heat recovery steam generator (HRSG) that generates steam, which is then used to produce power using a steam turbine (the steam cycle). Combining these generation cycles increases the overall efficiency of the system. Simple cycle combustion turbines use a single combustion turbine to produce electricity (
Coal-fired utility boilers are primarily either pulverized coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is crushed (pulverized) into a powder in order to increase its surface area. The coal powder is then blown into a boiler and burned. In a coal-fired boiler using FB combustion, the coal is burned in a layer of heated particles suspended in flowing air.
Power can also be generated using gasification technology. An IGCC unit gasifies coal or petroleum coke to form a synthetic gas (or syngas) composed of carbon monoxide (CO) and hydrogen (H
Natural gas prices have decreased dramatically and generally stabilized in recent years as new drilling techniques have brought additional supply to the marketplace and greatly increased the domestic resource base. As a result, natural gas prices are expected to be competitive for the foreseeable future, and EIA modeling and utility announcements confirm that utilities are likely to rely heavily on natural gas to meet new demand for electricity generation. On average, as discussed below, the cost of generation from a new natural-gas fired power plant (a NGCC unit) is expected to be significantly lower than the cost of generation from a new coal-fired power plant.
Other drivers that may influence decisions to build new power plants are increases in renewable energy supplies, often due to state and federal energy policies. As previously discussed, many states have adopted RPS, which require a certain portion of electricity to come from renewable energy sources such as solar or wind. The federal government has also offered incentives to encourage further deployment of other forms of electric generation including renewable energy sources and new nuclear power plants.
Reflecting these factors, the EIA projections from the last several years show that natural gas is likely to be the most widely-used fossil fuel for new construction of electric generating capacity through 2020, along with renewable energy, nuclear power, and a limited amount of coal with CCS.
While EIA data shows that natural gas is likely to be the most widely-used fossil fuel for new construction of electric generating capacity through 2030, a few coal-fired units still remain as viable projects at various advanced stages of construction and development. One new coal facility that has essentially completed construction,
Various energy sector modeling efforts, including projections from the EIA and the EPA, forecast trends in new power plant construction and utilization of existing power plants that are consistent with the above-described technological developments and costs. The EIA's annual report, the AEO, forecasts the structure of and developments in the power sector. These reports are based on economic modeling that reflects existing policy and regulations, such as state RPS programs and federal tax credits for renewables.
Specifically, the AEO 2015 projects 30.3 GW of additional base load or intermediate load generation capacity through 2020 (this includes projects that are under development—
Under the EIA projections, existing coal-fired generation will remain an important part of the mix for power generation. Modeling from both the EIA and the EPA project that coal-fired generation will remain the largest single source of electricity in the U.S. through 2040. Specifically, in the EIA's AEO 2015, coal will supply approximately 40 percent of all electricity in the electric power sector in both 2020 and 2025.
The EPA modeling using the Integrated Planning Model (IPM), a detailed power sector model that the EPA uses to support power sector regulations, also shows limited future construction of new coal-fired power plants under the base case.
The trends in the power sector described above are also apparent in publicly available long-term resource plans, known as integrated resource plans (IRPs).
The EPA has reviewed publicly available IRPs from a range of companies (
Notwithstanding this clear trend towards natural gas-fired generation and renewables, many of the IRPs highlight the value of fuel diversity and include options to diversify new generation capacity beyond natural gas and renewable energy. Several IRPs indicate that companies are considering new nuclear generation, including either traditional nuclear power plants or small modular reactors, and a smaller number are considering new coal-fired generation capacity with and without CCS technology. Based on public comments and on the information contained in these IRPs, the EPA acknowledges that a small number of
The U.S. Supreme Court ruled in
CAA section 111 authorizes and directs the EPA to prescribe new source performance standards (NSPS) applicable to certain new stationary sources (including newly constructed, modified and reconstructed sources).
Once the EPA has listed a source category, the EPA proposes and then promulgates “standards of performance” for “new sources” in the category.
The NSPS general provisions (40 CFR part 60, subpart A) provide that an existing source is considered to be a new source if it undertakes a “reconstruction,” which is the replacement of components of an existing facility to an extent that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards.
CAA section 111(a)(1) defines a “standard of performance” as “a standard for emissions . . . achievable through the application of the best system of emission reduction which [considering cost, non-air quality health and environmental impact, and energy requirements] the Administrator determines has been adequately demonstrated.” This definition makes clear that the standard of performance must be based on “the best system of emission reduction . . . adequately demonstrated” (BSER).
The standard that the EPA develops, reflecting the performance of the BSER, is commonly a numeric emission limit, expressed as a numeric performance level that can either be normalized to a rate of output or input (
The text and legislative history of CAA section 111, as well as relevant court decisions, identify the factors that the EPA is to consider in making a BSER determination. The system of emission reduction must be technically feasible, the costs of the system must be reasonable, and the emission standard that the EPA promulgates based on the system of emission reduction must be achievable. In addition, in identifying a BSER, the EPA must consider the amount of emissions reductions attributable to the system, and must also consider non-air quality health and environmental impacts and energy requirements. The case law addressing CAA section 111 makes it clear that the EPA has discretion in weighing costs, amount of emission reductions, energy requirements, and impacts of non-air quality pollutants, and may weigh them differently for different types of sources or air pollutants. We note that under the case law of the D.C. Circuit, another factor is relevant for the BSER determination: Whether the standard would effectively promote further deployment or development of advanced technologies. Within the constraints just described, the EPA has discretion in identifying the BSER and the resulting emission standard. See generally Section III.H below.
For more than four decades, the EPA has used its authority under CAA section 111 to set cost-effective emission standards which ensure that newly constructed, reconstructed, and modified stationary sources use the best performing technologies to limit emissions of harmful air pollutants. In this final action, the EPA is following the same well-established interpretation and application of the law under CAA section 111 to address GHG emissions from newly constructed, reconstructed, and modified fossil fuel-fired power plants. For each of the standards in this final action, the EPA considered a number of alternatives and evaluated them against the statutory factors. The BSER for each category of affected EGUs and the standards of performance based on these BSER are based on that evaluation.
In 1971, the EPA initially included fossil fuel-fired EGUs (which includes natural gas, petroleum and coal) that use steam-generating boilers in a category that it listed under CAA section 111(b)(1)(A),
The EPA has revised those regulations, and in some instances, has revised the codifications (that is, the 40 CFR part 60 subparts), several times over the ensuing decades. In 1979, the EPA divided subpart D into 3 subparts—Da (“Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978”), Db (“Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units”) and Dc (“Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units”)—in order to codify separate requirements that it established for these subcategories.
The EPA promulgated amendments to subpart Da in 2006, which included new standards of performance for criteria pollutants for EGUs, but did not include specific standards of performance for CO
On April 13, 2012, the EPA initially proposed standards under CAA section 111 for newly constructed fossil fuel-fired electric utility steam generating units. 77 FR 22392 (“April 2012 proposal”). The EPA withdrew that proposal (79 FR 1352 (January 8, 2014)), and, on the same day, proposed the standards addressed in this final rule. 79 FR 1430 (“January 2014 proposal”). Specifically, the EPA proposed standards under CAA section 111 to limit emissions of CO
In support of the January 2014 proposal, on February 26, 2014, the EPA published a notice of data availability (NODA) (79 FR 10750). Through the NODA and an associated technical support document,
On June 18, 2014, the EPA proposed standards of performance to limit emissions of CO
The EPA has engaged extensively with a broad range of stakeholders and the general public regarding climate change, carbon pollution from power plants, and carbon pollution reduction opportunities. These stakeholders included industry and electric utility representatives, state and local officials, tribal officials, labor unions, non-governmental organizations and many others.
In February and March 2011, early in the process of developing carbon pollution standards for new power plants, the EPA held five listening sessions to obtain information and input from key stakeholders and the public. Each of the five sessions had a particular target audience: The electric power industry, environmental and environmental justice organizations, states and tribes, coalition groups, and the petroleum refinery industry.
The EPA conducted subsequent outreach prior to the June 2014 proposals of standards for modified and reconstructed EGUs and emission guidelines for existing EGUs, as well as during the public comment periods for the proposals. Although this stakeholder outreach was primarily framed around the GHG emission guidelines for existing EGUs, the outreach encompassed issues relevant to this rulemaking and provided an opportunity for the EPA to better understand previous state and stakeholder experience with reducing CO
The EPA received more than 2.5 million comments submitted in response to the original April 2012 proposal for newly constructed fossil fuel-fired EGUs. Because the original proposal was withdrawn, the EPA instructed commenters that wanted their comments on the April 2012 proposal to be considered in connection with the January 2014 proposal to submit new comments to the EPA or to re-submit their previous comments. We received more comments in response to the January 2014 proposal, as discussed in the section below.
The EPA has given stakeholder input provided prior to the proposals, as well as during the public comment periods for each proposal, careful consideration during the development of this rulemaking and, as a result, it includes elements that are responsive to many stakeholder concerns and that enhance the rule. This preamble and the Response-to-Comments (RTC) document summarize and provide the agency's responses to the comments received.
Upon publication of the January 8, 2014 proposal for newly constructed fossil fuel-fired EGUs, the EPA provided a 60-day public comment period. On March 6, 2014, in order to provide the public additional time to submit comments and supporting information, the EPA extended the comment period by 60 days, to May 9, 2014, giving stakeholders over 120 days to review, and comment upon, the January 2014 proposal, as well as the NODA. A public hearing was held on February 6, 2014, with 159 speakers presenting testimony.
The EPA received more than 2 million comments on the proposed standards for newly constructed fossil fuel-fired EGUs from a range of stakeholders that included industry and electric utility representatives, trade groups, equipment manufacturers, state and local government officials, academia, environmental organizations, and various interest groups. The agency received comments on a range of topics, including the determination that a new highly-efficient steam generating EGU implementing partial CCS was the BSER for such sources, the level of the CO
Upon publication of the June 18, 2014 proposal for modified and reconstructed fossil fuel-fired EGUs, the EPA offered a 120-day public comment period—through October 16, 2014. The EPA held public hearings in four locations during the week of July 28, 2014. These hearings also addressed the EPA's June 18, 2014 proposed emission guidelines for existing fossil fuel-fired EGUs (reflecting the connections between the proposed standards for modified and reconstructed sources and the proposed emission guidelines). A total of 1,322 speakers testified, and a further 1,450 attended but did not speak. The speakers were provided the opportunity to present data, views, or arguments concerning one or both proposed actions.
The EPA received over 200 comments on the proposed standards for modified and reconstructed fossil fuel-fired EGUs from a range of stakeholders similar to those that submitted comments on the January 2014 proposal for newly constructed fossil fuel-fired EGUs (
In this section, we describe our authority to regulate CO
The EPA's authority for this rule is CAA section 111(b)(1). CAA section 111(b)(1)(A) requires the Administrator to establish a list of source categories to be regulated under section 111. A category of sources is to be included on the list “if in [the Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare.” This determination is commonly referred to as an “endangerment finding” and that phrase encompasses both the “causes or contributes significantly” component and the “endanger public health and welfare” component of the determination. Then, for the source categories listed under section 111(b)(1)(A), the Administrator promulgates, under section 111(b)(1)(B), “standards of performance for new sources within such category.”
In this rule, the EPA is establishing standards under section 111(b)(1)(B) for source categories that it has previously listed and regulated for other pollutants and which now are being regulated for an additional pollutant. Because of this, there are two aspects of section 111(b)(1) that warrant particular discussion.
First, because the EPA is not listing a new source category in this rule, the EPA is not required to make a new endangerment finding with regard to affected EGUs in order to establish standards of performance for the CO
Second, once a source category is listed, the CAA does not specify what pollutants should be the subject of standards from that source category. The statute, in section 111(b)(1)(B), simply directs the EPA to propose and then promulgate regulations “establishing federal standards of performance for new sources within such category.” In the absence of specific direction or enumerated criteria in the statute concerning what pollutants from a given source category should be the subject of standards, it is appropriate for the EPA to exercise its authority to adopt a reasonable interpretation of this provision.
The EPA has previously interpreted this provision as granting it the discretion to determine which pollutants should be regulated.
In exercising its discretion with respect to which pollutants are appropriate for regulation under section 111(b)(1)(B), the EPA has in the past provided a rational basis for its decisions. See
In this rulemaking, the EPA has a rational basis for concluding that emissions of CO
Moreover, the high level of GHG emissions from fossil fuel-fired EGUs makes clear that it is rational for the EPA to regulate GHG emissions from this sector. EGUs emit almost one-third of all U.S. GHGs and comprise by far the largest stationary source category of GHG emissions; indeed, as noted above, the CO
Some commenters have argued that the EPA is required to make a new endangerment finding before it may regulate CO
More specifically, our approach here—reflected in the information and conclusions described above—is substantially similar to that reflected in the 2009 Endangerment Finding and the 2010 denial of petitions to reconsider. The D.C. Circuit upheld that approach in
Likewise, if the EPA were required to make a cause-or-contribute-significantly finding for CO
As discussed in the January 2014 proposal of carbon pollution standards for newly constructed EGUs (79 FR 1430) and above, in 1971 the EPA listed fossil fuel-fired steam generating boilers as a new category subject to CAA section 111 rulemaking, and in 1979 the EPA listed fossil fuel-fired combustion turbines as a new category subject to the CAA section 111 rulemaking. In the ensuing years, the EPA has promulgated standards of performance for the two categories and codified those standards, at various times, in 40 CFR part 60, subparts D, Da, GG, and KKKK.
In the January 2014 proposal of carbon pollution standards for newly constructed EGUs (79 FR 1430) and the June 2014 proposal of carbon pollution standards for modified and reconstructed EGUs (79 FR 34960), the EPA proposed separate standards of performance for new, modified, and reconstructed sources in the two categories. The EPA took comment on combining the two categories into a single category solely for purposes of the CO
In this rule, the EPA is combining the steam generator and combustion turbine categories into a single category of fossil fuel-fired electricity generating units for purposes of promulgating standards of performance for GHG emissions. Combining the two categories is reasonable because they both provide the same product: Electricity services. Moreover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for existing sources that accompanies this rule. In addition,
Because these two source categories are pre-existing listed source categories and the EPA will not be subjecting any additional sources in the categories to CAA regulation for the first time, the combination of these two categories is not considered a new source category subject to the listing requirements of CAA section 111(b)(1)(A). As a result, this final rule does not list a new category under CAA section 111(a)(1)(A), nor does this final rule revise either of the two source categories. Thus, the EPA is not required to make a new endangerment and contribution finding for the combination of the two categories,
We generally refer to fossil fuel-fired electric generating units that would be subject to a CAA section 111 emission standard as “affected” or “covered” sources, units, facilities or simply as EGUs. An EGU is any boiler, IGCC unit, or combustion turbine (in either simple cycle or combined cycle configuration) that meets the applicability criteria. Affected EGUs include those that commenced construction after January 8, 2014, and meet the specified applicability criteria and, for modifications and reconstructions, EGUs that commenced those activities after June 18, 2014, and meet the specified applicability criteria.
To be considered an EGU, the unit must: (1) Be capable of combusting more than 250 MMBtu/h (260 GJ/h) heat input of fossil fuel;
As described in the previous section, the EPA is not issuing standards of performance for certain types of sources—specifically, dedicated non-fossil fuel-fired (
The proposed applicability for newly constructed EGUs included those that primarily combust fossil fuels (
While the proposed exemption applied to all non-fossil fuels, most commenters focused on biomass-specific issues. Many commenters supported an exclusion for biomass-fired units that fire no more than 10 percent fossil fuels. Some commenters suggested that the exclusion for biomass-fired units should be raised to a 25 percent fossil fuel-use threshold.
Many commenters supported the proposed 3-year averaging period for the fossil fuel-use criterion because it provides greater flexibility for operators to use fossil fuels when supply chains for the primary non-fossil fuels are disrupted, during unexpected malfunctions of the primary non-fossil fuel handling systems, or when the unit's maximum generating capacity is required by system operators for reliability reasons. Many commenters supported the 3-year averaging period because it is consistent with the final requirements under the EPA's Mercury and Air Toxics Standards (MATS) and would allow non-fossil fuel-fired units to use some fossil fuels for flame stabilization without triggering applicability. Some commenters requested that the EPA clarify the method an operator should use during the first 3 years of operations to determine if a particular unit will meet the 10 percent fossil fuel-use threshold. Others asked whether or not an affected facility has a compliance obligation during the first 3-year period and, if an
After considering these comments, the EPA has concluded that the proposed fossil fuel-use criterion based on the actual amount of fossil fuel burned is not an ideal approach to determine applicability. As commenters pointed out, facilities, permitting authorities, and the public would not know when construction is commenced whether a facility will be subject to the final NSPS, and after operation has commenced, a unit could move in and out of applicability each year. The intent of this rulemaking is to establish CO
We considered using either an annual or 3-year average for calculating compliance with the final fossil fuel-use criterion. Ultimately, we concluded that an annual average would provide sufficient flexibility for dedicated non-fossil units to combust fossil fuels for flame stabilization and other ancillary purposes, while maintaining consistency with the 12-month compliance periods used for most permit limitations. A 3-year average potentially would allow units to combust a significant quantity of fuels in a given year, leading to higher CO
Another approach to generating electricity is the use of CHP units. A CHP unit can use a boiler, combustion turbine, reciprocating engine, or various other generating technologies to generate electricity and useful thermal energy in a single, integrated system. CHP units are generally more efficient than conventional power plants because the heat that is normally wasted in a conventional power generation cooling system (
Many commenters supported the exclusion of CHP units as a means of encouraging capital investments in highly efficient and reliable distributed generation technologies. These commenters recommended that the EPA adopt an explicit exemption for CHP units at facilities that are classified as industrial (
Other commenters suggested exempting CHP units by fuel type or based on the definition of potential electric output. For example, some commenters suggested modifying the percentage electric sales threshold to be based on net system efficiency (including useful thermal output) rather than the rated net-electric-output efficiency. They also suggested that the applicability criteria should use a default efficiency of 50 percent for CHP units. Some commenters suggested that a CHP unit should not be considered an affected EGU if 20 percent or more of its total gross or net energy output consisted of useful thermal output on a 3-year rolling average basis. Other commenters said that highly efficient CHP units that achieve an overall efficiency level of 60 to 70 percent or higher should be excluded from applicability.
The intent of this rulemaking is to cover only utility CHP units, because they serve essentially the same purpose as electric-only EGUs (
We rejected many of the approaches suggested by the commenters because they did not achieve one or both of the factors we identified. Specifically, the EPA has concluded that SIC code classification is not a sufficient indicator of the purpose (
On the other hand, exemptions based on useful thermal output being greater than 20 percent of total output, thermal output being greater than electric output, or overall design efficiency value would identify whether the primary purpose of a unit is to generate thermal output, but they would not recognize the environmental benefits of highly efficient CHP units. While overall efficiency may appear to be a good indicator of environmental benefits, this is not always the case with CHP units. Overall efficiency is a function of both efficient design and the power to heat ratio (the amount of electricity relative to the amount of useful thermal output). For example, boiler-based CHP units tend to produce large amounts of useful thermal output relative to electric output and tend to have high overall efficiencies. For units producing primarily useful thermal output, the equivalent separate heat and power efficiency (
In the end, the EPA has concluded that maintaining the proposed percentage electric sales criterion with two adjustments addresses both factors with which we are concerned. First, we are changing the definition of “potential electric output” to be based on overall net efficiency at the maximum electric production rate, instead of just electric-only efficiency. Second, we are changing the percentage electric sales criterion to reflect the sliding scale, which is the overall design efficiency, calculated at the maximum useful thermal rating of the CHP unit (
In conclusion, a CHP unit will be an affected source unless it is subject to a federally enforceable permit that limits annual total electric sales to less than or equal to the unit's design efficiency multiplied by its potential electric output or 219,000 MWh,
CHP facilities with a steam extraction condensing steam turbine will determine their potential electric output based on their efficiency on a net basis at the maximum electric production rate at the base load heat input rating (
New EGUs with only limited useful thermal output will be subject to the final standards, but the vast majority of new CHP units will be classified as industrial CHP and will not be subject to the final standards. The EPA has concluded that this approach is similar to exempting CHP facilities that sell less than half of their total output (electricity plus thermal), but has the benefit of accounting for overall design efficiency.
The purpose of this rulemaking is to establish CO
The EPA proposed that a limited class of projects under development should not be subject to the proposed standards. These were planned sources that may be capable of commencing construction (within the meaning of section 111(a)) shortly after the standard's proposal date, and so would be classified as new sources, but which have a design which would be incapable of meeting the proposed standard of performance. See 79 FR 1461 and CAA section 111(a)(2). The EPA proposed that these sources would not be subject to the generally-applicable standard of performance, but rather would be subject to a unit-specific permitting determination if and when construction actually commences. The EPA indicated that there could be three sources to which this approach could apply, and further indicated that the EPA could ultimately adopt the generally-applicable standard of performance for these sources (if actually constructed). 79 FR 1461.
As explained at Section III.J below, the EPA is finalizing this approach in this final rule. We again note that these sources, if and when constructed, could be ultimately subject to the 1,400 lb CO
In the April 2012 proposal, we solicited comment on subcategorizing and exempting EGUs that burn over 75 percent coal refuse on an annual basis. Multiple commenters supported the exemption, citing numerous environmental benefits of remediating coal refuse piles. Observing that coal refuse-fired EGUs typically use fluidized bed technologies, other commenters disagreed with any exemption, specifically citing the N
Commenters said that a performance standard is not feasible for coal refuse CFBs since there is no economically feasible way to capture CO
The EPA has concluded that an explicit exemption or subcategory specifically for coal refuse-fired EGUs is not appropriate. The costs faced by coal refuse facilities to install CCS are similar to coal-fired EGUs burning any of the primary coals, and the final applicable requirements and standards in the rule do not preclude the development of new coal refuse-fired units without CCS. Specifically, we are not finalizing CO
For all newly constructed units, the EPA proposed standards as gross output emission rates consistent with current monitoring and reporting requirements under 40 CFR part 75.
Many commenters supported gross-output-based standards, maintaining that a net-output standard penalizes the operation of air pollution control equipment. Several commenters disagreed with the agency's proposed rationale that a net-output standard would provide incentive to minimize auxiliary loads. The commenters believe utility commissions and existing economic forces already provide utilities with appropriate incentives to properly manage all of these factors. Some commenters supported a gross-output-based standard because variations in site conditions (
Several commenters opposed net-output-based standards because they believe it is difficult to accurately determine the net output of an EGU. They pointed out that many facilities have transformers that support multiple units at the facility, making unit-level reporting difficult. These commenters also stated that station electric services may come from outside sources to supply certain ancillary loads. One commenter stated that the benefit of switching to net-output-based standards would be small and would not justify the substantial complexities in both defining and implementing such a standard. Conversely, other commenters stated that net-metering is a well-established technology that should be required, particularly for newly constructed units.
Other commenters, however, maintained that the final rule should strictly require compliance on a net output-basis. They believe that this is the only way for the standards to minimize the carbon footprint of the electricity delivered to consumers. These commenters believe that, at a minimum, net-output-based standards should be included as an option in the final rule.
We are only finalizing gross-output-based standards for utility boilers and IGCC units. Providing an alternate net-output-based standard that is based on gross-output-based emissions data and an assumed auxiliary load is most appropriate when the auxiliary load can be reasonably estimated and the choice between the net- and gross-output-based standard will not impact the identified BSER. For example, the auxiliary load for combustion turbines is relatively fixed and small, approximately 2.5 percent, so the choice between a gross and net-output-based standard will not substantially impact technology choices. However, in the case of utility boilers, we have concluded that we do not have sufficient information to establish an appropriate net-output-based standard that would not impact the identified BSER for these types of units. The BSER for newly constructed steam generating units is based on the use of partial CCS. However, unlike the case for combustion turbines, owners/operators of utility boilers have multiple technology pathways available to comply with the actual emission standard. The choice of both control technologies and fuel impact the overall auxiliary load. For example, a coal-fired hybrid EGU (
In contrast, based on further evaluation and review of issues raised by commenters, the EPA is finalizing the CO
The rule specifies an alternative net-output-based standard of 1,030 lb CO
The procedures for requesting this alternative net-output-based standard require the owner or operator to petition the Administrator in writing to comply with the alternate applicable net-output-based standard. If the Administrator grants the petition, this election would be binding and would be the unit's sole means of demonstrating compliance. Owners or operators complying with the net-output-based standard must similarly petition the Administrator to switch back to complying with the gross-output-based standard.
For CHP units, useful thermal output is also used when determining the emission rate. Previous rulemakings issued by the EPA have prescribed various “discount factors” of the measured useful thermal output to be used when determining the emission rate. We proposed that 75 percent credit is the appropriate discount factor for useful thermal output, and we solicited
Many commenters said that in order to fully account for the environmental benefits of CHP and to reflect the environmental benefits of CHP, the EPA should allow 100 percent of the useful thermal output from CHP units. Commenters noted that providing 100 percent credit for useful thermal output is consistent with the past practice of the EPA in the stationary combustion turbine criteria pollutant NSPS and state approaches for determining emission rates for CHP units.
Based on further consideration and review of the comments submitted, we are finalizing 100 percent credit for useful thermal output for all newly constructed, modified, and reconstructed CHP sources. We have concluded that this is appropriate because, at the same reported emission rate, a hypothetical CHP unit would have the same overall GHG emissions as the combined emission rate of separate heat and power facilities. Any discounting of useful thermal output could distort the market and discourage the development of new CHP units. Full credit for useful thermal output appropriately recognizes the environmental benefit of CHP.
The air pollutant regulated in this final action is greenhouse gases. However, the standards in this rule are expressed in the form of limits on only emissions of CO
In the January 2014 proposal, we described the principal legal requirement for standards of performance under CAA section 111(b), which is that the standards of performance must consist of standards for emissions that reflect the degree of emission limitation achievable though the application of the “best system of emission reduction . . . adequately demonstrated,” taking into account cost and any non-air quality health and environment impact and energy requirements. We noted that the D.C. Circuit has handed down numerous decisions that interpret this CAA provision, including its component elements, and we reviewed that case law in detail.
We received comments on our proposed interpretation, and in light of those comments, in this rule, we are clarifying our interpretation in certain respects. We discuss our interpretation below.
As noted above, the CAA section 111 requirements that govern this rule are as follows: As the first step towards establishing standards of performance, the EPA “shall publish . . . a list of categories of stationary sources . . . [that] cause[ ], or contribute[ ] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” CAA section 111(b)(1)(A). Following that listing, the EPA “shall publish proposed regulations, establishing federal standards of performance for new sources within such category” and then “promulgate . . . such standards” within a year after proposal. CAA section 111(b)(1)(B). The EPA “may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing such standards.” CAA section 111(b)(2). The term “standard of performance” is defined to “mean[ ] a standard for emissions . . . achievable through the application of the best system of emission reduction which [considering cost, non-air quality health and environmental impact, and energy requirements] the Administrator determines has been adequately demonstrated.” CAA section 111(a)(1).
As noted in the January 2014 proposal, Congress first included the definition of “standard of performance” when enacting CAA section 111 in the 1970 Clean Air Act Amendments (CAAA), amended it in the 1977 CAAA, and then amended it again in the 1990 CAAA to largely restore the definition as it read in the 1970 CAAA. It is in the legislative history for the 1970 and 1977 CAAAs that Congress primarily addressed the definition as it read at those times, and that legislative history provides guidance in interpreting this provision.
In the 1977 CAAA, Congress revised the definition to distinguish among different types of sources, and to require that for fossil fuel-fired sources, the standard: (i) Be based on, in lieu of the “best system of emission reduction . . . adequately demonstrated,” the “best technological system of continuous emission reduction . . . adequately demonstrated;” and (ii) require a percentage reduction in emissions. In addition, in the 1977 CAAA, Congress expanded the parenthetical requirement that the Administrator consider the cost of achieving the reduction to also require the Administrator to consider “any nonair quality health and environment impact and energy requirements.”
In the 1990 CAAA, Congress again revised the definition, this time repealing the requirements that the standard of performance be based on the best technological system and achieve a percentage reduction in emissions, and replacing those provisions with the terms used in the 1970 CAAA version of section 111(a)(1) that the standard of performance be based on the “best system of emission reduction . . . adequately demonstrated.” This 1990 CAAA version is the current definition. Even so, because parts of the definition as it read under the 1977 CAAA were retained in the 1990 CAAA, the explanation in the 1977 CAAA legislative history, and the interpretation in the case law, of those parts of the definition in the case law remain relevant to the definition as it reads today.
By its terms, the definition of “standard of performance” under CAA section 111(a)(1) provides that the emission limits that the EPA promulgates must be “achievable” by application of a “system of emission reduction” that the EPA determines to be the “best” that is “adequately demonstrated,” “taking into account . . . cost . . . nonair quality health and environmental impact and energy requirements.” The D.C. Circuit has stated that, in determining the “best” system, the EPA must also take into account “the amount of air pollution”
Our overall approach to determining the BSER, which incorporates the various elements, is as follows: First, the EPA identifies the “system[s] of emission reduction” that have been “adequately demonstrated” for a particular source category. Second, the EPA determines the “best” of these systems after evaluating extent of emission reductions, costs, any non-air health and environmental impacts, and energy requirements. And third, the EPA selects an achievable standard for emissions—here, the emission rate—based on the performance of the BSER. The remainder of this subsection discusses the various elements in that analytical approach.
The EPA's first step is to identify “system[s] of emission reduction . . . adequately demonstrated.” For the reasons discussed below, for the various types of newly constructed, modified, and reconstructed sources in this rulemaking, the EPA focused on efficient generation, add-on controls, efficiency improvements, and clean fuels as the systems of emission reduction.
An “adequately demonstrated” system, according to the D.C. Circuit, is “one which has been shown to be reasonably reliable, reasonably efficient, and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.”
As the January 2014 proposal indicates, the requirement that the standard for emissions be “achievable” based on the “best system of emission reduction . . . adequately demonstrated” indicates that one of the requirements for the technology or other measures that the EPA identifies as the BSER is that the measure must be technically feasible. See 79 FR 1430, 1463 (January 8, 2014).
In determining which adequately demonstrated system of emission reduction is the “best,” the EPA considers the following factors:
Under CAA section 111(a)(1), the EPA is required to take into account “the cost of achieving” the required emission reductions. As described in the January 2014 proposal,
In the [1970] Congress [
1977 House Committee Report at 184. Similarly, the 1970 Senate Committee Report stated:
The implicit consideration of economic factors in determining whether technology is “available” should not affect the usefulness of this section. The overriding purpose of this section would be to prevent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach.
S. Comm. Rep. No. 91-1196 at 16. Some commenters asserted that we do not have authority to revise the cost standard as established in the case law,
The D.C. Circuit has indicated that the EPA has substantial discretion in its consideration of cost under section 111(a). In several cases, the Court upheld standards that entailed significant costs, consistent with Congress's view that “the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business.”
As discussed below, the EPA may consider costs on both a source-specific basis and a sector-wide, regional, or nationwide basis. The EPA is finding here that whether costs are considered on a source-specific basis, an industry/national basis, or both, they are reasonable. See Sections V.H and I below.
Under CAA section 111(a)(1), the EPA is required to take into account “any nonair quality health and environmental impact” in determining the BSER. As the D.C. Circuit has explained, this requirement makes explicit that a system cannot be “best” if it does more harm than good due to cross-media environmental impacts.
Under CAA section 111(a)(1), the EPA is required to take into account “energy requirements.” As discussed below, the EPA may consider energy requirements on both a source-specific basis and a sector-wide, region-wide, or nationwide basis. Considered on a source-specific basis, “energy requirements” entail, for example, the impact, if any, of the system of emission reduction on the source's own energy needs. In this rulemaking, as discussed below in Section V.O.3, the EPA considered the parasitic load requirements of partial CCS. The EPA is finding here that whether energy requirements are considered on a source-specific basis, an industry/national basis, or both, they are reasonable. See Sections V.O.3 and XIII.C.
At proposal, we noted that although the definition of “standard of performance” does not by its terms identify the amount of emissions from the category of sources or the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” the D.C. Circuit has stated that the EPA must in fact do so.
As discussed in the January 2014 proposal, another component of the D.C. Circuit's interpretations of CAA section 111 is that the EPA may consider the various factors it is required to consider on a national or regional level and over time, and not only on a plant-specific level at the time of the rulemaking.
The Conferees defined the best technology in terms of “long-term growth,” “long-term cost savings,” effects on the “coal market,” including prices and utilization of coal reserves, and “incentives for improved technology.” Indeed, the Reports from both Houses on the Senate and House bills illustrate very clearly that Congress itself was using a long-term lens with a broad focus on future costs, environmental and energy effects of different technological systems when it discussed section 111.
The Court has upheld rules that the EPA “justified . . . in terms of the policies of the Act,” including balancing long-term national and regional impacts:
The standard reflects a balance in environmental, economic, and energy consideration by being sufficiently stringent to bring about substantial reductions in SO
By substantially reducing SO
Some commenters objected that this case law did not allow the EPA to ignore source-specific impacts (particularly cost impacts) by basing determinations solely on impacts at a regional or national level. In fact, the EPA's consideration of cost, non-air quality impacts, and energy requirements reflect source-specific impacts, as well as (for some considerations) impacts that are sector-wide, regional, or national. See Section V.H.6 below.
In the January 2014 proposal, the EPA recognized that the first element of the definition of “standard of performance” is that “the emission limit [
In Sections V.J and IX.D below, we show both that the BSER for new steam generating units and combustion turbines is technically feasible and adequately demonstrated, and that the standards of 1,400 lb CO
In the January 2014 proposal, we noted that the D.C. Circuit has made clear that Congress intended for CAA section 111 to create incentives for new technology and therefore that the EPA is required to consider technological innovation as one of the factors in determining the “best system of emission reduction.”
The Court grounded its reading in the statutory text.
Commenters stated that the requirement to consider technological innovation does not authorize the EPA to identify as the BSER a technology that is not adequately demonstrated. The proposal did not, and we do not in this final rule, claim to the contrary. In any event, as discussed below, the EPA may justify the control technologies identified in this rule as the BSER even without considering the factor of incentivizing technological innovation or development.
As discussed in the January 2014 proposal, the D.C. Circuit has made clear that the EPA has broad discretion in determining the appropriate standard of performance under the definition in CAA section 111(a)(1), quoted above. Specifically, in
Because section 111 does not set forth the weight that should be assigned to each of these factors, we have granted the agency a great degree of discretion in balancing them. . . . EPA's choice [of the `best system'] will be sustained unless the environmental or economic costs of using the technology are exorbitant. . . . EPA [has] considerable discretion under section 111.
In the January 2014 proposal, the EPA proposed that, under CAA section 111, an emissions standard may meet the requirements of a “standard of performance” even if it cannot be met by every new source in the source category that would have constructed in the absence of that standard. As described in the January 2014 proposal, the EPA based this view on (i) the legislative history of CAA section 111, read in conjunction with the legislative history of the CAA as a whole; (ii) case law under analogous CAA provisions; and (iii) long-standing precedent in the EPA rulemakings under CAA section 111.
Commenters contested this assertion, arguing that a 111(b) standard must be achievable by all new sources. We continue to take the same position as at proposal for the reasons described there. We note that as a practical matter, in this rulemaking, the issue of whether all new steam-generating sources can implement partial-capture CCS is largely dependent on the geographic scope of geologic sequestration sites. As discussed below in Section V.M, geologic sequestration sites are widely available, and a steam-generating plant with partial CCS that is sited near an area that is suitable for geologic sequestration can serve demand in a large area that may not have sequestration sites available. In any event, the standard of 1,400 lb CO
The Energy Policy Act of 2005 (“EPAct05”) authorizes assistance in the form of grants, loan guarantees, as well as federal tax credits for investment in “clean coal technology.” Sections 402(i), 421(a), and 1307(b) (adding section 48A(g) to the Internal Revenue Code (“IRC”)) address the extent to which information from clean coal projects receiving assistance under the EPAct05 may be considered by the EPA in determining what is the best system of emission reduction adequately demonstrated. Section 402(i) of the EPAct05 limits the use of information from facilities that receive assistance under EPAct05 in CAA section 111 rulemakings:
“No technology, or level of emission reduction, solely by reason of the use of the technology, or the achievement of the emission reduction, by 1 or more facilities receiving assistance under this Act, shall be considered to be adequately demonstrated [ ] for purposes of section 111 of the Clean Air Act. . . .”
IRC section 48A(g) contains a similar constraint concerning the use of technology or level of emission reduction from EGU facilities for which a tax credit is allowed:
“No use of technology (or level of emission reduction solely by reason of the use of the technology), and no achievement of any emission reduction by the demonstration of any technology or performance level, by or at one or more facilities with respect to which a credit is allowed under this section, shall be considered to indicate that the technology or performance level is adequately demonstrated [ ] for purposes of section 111 of the Clean Air Act. . . .”
The EPA specifically solicited comment on its interpretation of these provisions. 79 FR 10750 (Feb. 26, 2014) (Notice of Data Availability). With respect to EPAct05 sections 402(i) and 421(a), the EPA proposed that these provisions barred consideration where EPAct05-assisted facilities were the sole support for the BSER determination, but that these sources could support a BSER determination so long as there is additional evidence supporting the determination.
Some commenters supported the EPA's proposed interpretation. Others contended that the EPA's interpretation would allow it to support a BSER determination even where EPAct05 facility information comprised 99 percent of the supporting information for a BSER determination because that determination would not be based “solely” on EPAct05 sources. These commenters urged the EPA to conclude that a determination “solely” on the basis of information from EPAct05-assisted facilities is any determination where “but for” that information, the EPA could not justify its chosen standard as the BSER.
In this final rule, the EPA is adopting the interpretations of all three provisions that it proposed, largely for the reasons previously advanced. The EPA thus interprets these provisions to preclude the EPA from relying solely on the experience of facilities that received DOE assistance, but not to preclude the EPA from relying on the experience of such facilities in conjunction with other information. This reading of sections 402(i) and 421(a) is consistent with the views of the only court to date to consider the matter.
The EPA notes that the extreme hypothetical posed in the comments (where the EPA might avoid a limitation on its consideration of EPAct05-assisted facilities by including a mere scintilla of evidence from non-EPAct05 facilities) is not presented here, where the principal evidence that partial post-combustion CCS is a demonstrated and feasible technology comes from sources which received no assistance of any type under EPAct05. The EPA also concludes that the “but for” test urged by these commenters is an inappropriate reading of the term “solely” in sections 402(i) and 421(a), as any piece of evidence may be a necessary, or “but for,” cause without being a sufficient, or “sole,” cause.
Other commenters took the extreme position that the EPAct05 provisions bar all consideration of a facility's existence if the facility received EPAct05 assistance.
In any case, as shown in Section V below, the EPA finds that a new highly-efficient SCPC EGU implementing partial post-combustion CCS is the best system of emission reduction adequately demonstrated and is doing so based in greater part on performance of facilities receiving no assistance under EPAct05, and on other information likewise not having any connection to EPAct05 assistance. The corroborative information from EPAct05 facilities, though supportive, is not necessary to the EPA's findings.
This rule has numerous components, and the EPA intends that they be severable from each other to the extent that they function separately. For example, the EPA intends that each set of BSER determinations and standards of performance in this rulemaking be severable from each other set. That is, the BSER determination and standard of performance for newly constructed fossil fuel-fired electric utility steam generating units are severable from all the other BSER determinations and standards of performance, and the same is true for the BSER determination and standard of performance for modified fossil fuel-fired electric utility steam generating units, and so on. It is reasonable to consider each set of BSER determination and standard of performance to be severable from each other set of BSER determination and standard of performance because each set is independently justifiable and does not depend on any other set. Thus, in the event that a court should strike down any set of BSER determination and standard of performance, the remaining BSER determinations and standards of performance should not be affected.
In the January 2014 proposal, the EPA indicated that the proposed Wolverine EGU project (Rogers City, Michigan) appeared to be the only fossil fuel-fired steam generating unit that was currently under development that may be capable of “commencing construction” for NSPS purposes at the time of the proposal. See 79 FR 1461. The EPA also acknowledged that the Wolverine EGU, as designed, would not meet the proposed standard of 1,100 lb CO
In December 2013—after the proposed action was signed, but before it was published—Wolverine Power Cooperative announced that it was cancelling construction of the proposed coal-fired power plant in Rogers City, MI.
In the January 2014 proposal, the EPA also identified two other fossil fuel-fired steam generating EGU projects that, as currently designed, would not meet the proposed 1,100 lb CO
To date, neither developer has sought a formal EPA determination of NSPS applicability. As we specified in the January 2014 proposal—and we reiterate here—if such an applicability determination concludes that either the Plant Washington (GA) project or the Holcomb 2 (KS) project did not commence construction prior to January 8, 2014 (the publication of the January 2014 proposal), then the project should be situated similarly to the disposition the EPA proposed for the Wolverine project. Accordingly, the EPA is finalizing in this action that if it is determined that either of these projects has not commenced construction as January 8, 2014, then that project will be addressed in the same manner as was proposed for the Wolverine project.
In public comments submitted in response to the January 2014, Power4Georgians (P4G), the Plant Washington developer, reiterated that they had executed binding contracts for the purchase and erection of the facility boiler prior to publication of the January 2014 proposal and believe that the binding contracts are sufficient to constitute commencement of construction for purposes of the NSPS program, so that they are existing rather than new sources for purposes of this
In October 2013, the Kansas Supreme Court invalidated the 2010 air pollution permit granted to Sunflower Electric Power Corporation by the Kansas Department of Health and Environment (KDHE).
In October 2014, the Plant Washington project was given an 18-month air permit extension by the Georgia Environmental Protection Division (EPD). However, as with the Holcomb expansion project, the EPA is unaware of any physical construction that has taken place at the proposed Plant Washington site and a recent audit of the project described it as “dormant”.
Based on this information, it appears that these sources have not commenced construction for purposes of section 111(b) and therefore would likely be new sources should they actually be constructed. As noted above, the EPA proposed that, if these projects are determined to not have commenced construction for NSPS purposes prior to the publication of the proposed rule, they will be addressed in the same manner proposed for the Wolverine project. 79 FR 1461. We are finalizing that proposal here. However, because these units may never actually be fully built and operated, we are not promulgating a standard of performance at this time because such action may prove to be unnecessary.
There is one possible additional new EGU, the Two Elk project in Wyoming. In a supporting TSD accompanying the January 2014 proposal, we discussed the Two Elk project and relied on developer statements and state acquiescence that the unit had commenced construction for NSPS purposes before January 8, 2014.
This section sets forth the standards for newly constructed, modified, and reconstructed steam generating units (
We generally refer to fossil fuel-fired electric utility generating units that would be subject to an emission standard in this rulemaking as “affected” or “covered” sources, units, facilities or simply as EGUs. These units meet both the definition of “affected” and “covered” EGUs subject to an emission standard as provided by this rule, and the criteria for being considered “new,” “modified” or “reconstructed” sources as defined under the provisions of CAA section 111 and the EPA's regulations. This section discusses applicability for newly constructed, modified, and reconstructed steam generating units.
The EPA is finalizing applicability criteria for new, modified, and reconstructed electric utility steam generating units (
The applicability requirements in the proposal for newly constructed EGUs included that a utility boiler or IGCC unit must: (1) Be capable of combusting more than 250 MMBtu/h heat input of fossil fuel; (2) be constructed for the purpose of supplying, and actually supply, more than one-third of its potential net-electric output capacity to any utility power distribution system (that is, to the grid) for sale on an annual basis; (3) be constructed for the purpose of supplying, and actually supply, more than 219,000 MWh net-electric output to the grid on an annual basis; and (4) combust over 10 percent fossil fuel on a heat input basis over a 3-year average. At proposal, applicability was determined based on a combination of design and actual operating conditions that could change annually depending on the proportion and the amount of electricity actually sold and on the proportion of fossil fuels combusted by the unit.
In the proposal for modified and reconstructed EGUs, we proposed a broader applicability approach such that applicability would be based solely on design criteria and would be identical to the applicability requirements in
We solicited comment on whether, to avoid implementation issues related with different interpretations of “constructed for the purpose,” the total and percentage electric sales criteria should be recast to be based on permit conditions. The “constructed for the purpose” language was included in the original subpart Da rulemaking. At that time, the vast majority of new steam generating units were clearly base load units. The “constructed for the purpose” language was intended to exempt industrial CHP units. These units tend to be relatively small and were not the focus of the rulemaking. In addition, units not meeting the electric sales applicability criteria in subpart Da would be covered by other NSPS so there is limited regulatory incentive, or impact to the environment, for owners/operators to avoid applicability with the utility NSPS. However, for new units, there is no corresponding industrial unit CO
This action finalizes applicability criteria based on design characteristics and federally enforceable permit restrictions included in each individual permit. Based on restrictions, if any, on annual total electric sales in the operating permit, it will be clear from the time of construction whether or not a new unit is subject to this rule. The applicability includes all utility boilers and IGCC units unless the electric sales restriction was in the original and remains in the current operating permit without any lapses (this is to be consistent with the `constructed for the purpose of' criteria in subpart Da). We have concluded that this approach is equivalent to, but clearer than, the existing language used in subpart Da. In addition, we have concluded that it is important for both the 111(b) and 111(d) requirements for electric-only steam generating units that the permit restriction limiting annual electric sales be included in both the original and current operating permit. Without this restriction, existing units could avoid obligations under state plans developed as part of the 111(d) program by amending their operating permit to limit total annual electric sales to one-third of potential electric output. These units would not be subject to any GHG NSPS requirements because they would not meet the 111(b) or 111(d) applicability criteria and, at this time, there is no NSPS that would cover these units. As described in Section III, industrial CHP and dedicated non-fossil units also are not affected EGUs under this final action.
In this rule, we are finalizing the definition of a steam generating EGU as a utility boiler or IGCC unit that: (1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either alone or in combination with any other fuel) and (2) serves a generator capable of supplying more than 25 MW-net to a utility distribution system (
In CAA section 111(a)(2), a “new source” is defined as any stationary source, the construction or modification of which is commenced after the publication of regulations (or if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source. Accordingly, for purposes of this rule, a newly constructed steam generating EGU is a unit that fits the definition and applicability criteria of a fossil fuel-fired steam generating EGU and commences construction on or after January 8, 2014, which is the date that the proposed standards were published for those sources (see 79 FR 1430).
In CAA section 111(a)(4), a “modification” is defined as “any physical change in, or change in the method of operation of, a stationary source” that either “increases the amount of any air pollutant emitted by such source or . . . results in the emission of any air pollutant not previously emitted.” The EPA, through regulations, has determined that certain types of changes are exempt from consideration as a modification.
For purposes of this rule, a modified steam generating EGU is a unit that fits the definition and applicability criteria of a fossil fuel-fired steam generating EGU and that modifies on or after June 18, 2014, which is the date that the proposed standards were published for those sources (see 79 FR 34960).
The NSPS general provisions (40 CFR part 60, subpart A) provide that an existing source is considered a new source if it undertakes a “reconstruction,” which is the replacement of components of an existing facility to an extent that: (1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards.
For purposes of this rule, a reconstructed steam generating EGU is a unit that fits the definition and applicability criteria of a fossil fuel-fired steam generating EGU and that reconstructs on or after June 18, 2014, which is the date that the proposed standards were published for those sources (see 79 FR 34960).
In the January 2014 proposal, the EPA proposed that highly efficient new generation technology implementing partial CCS is the BSER for GHG emissions from new steam generating EGUs. (See generally 79 FR 1468-1469.) In this final action, the EPA has determined that the BSER for newly constructed steam generating units is a new highly efficient supercritical pulverized coal (SCPC) boiler implementing partial CCS technology to the extent of removal efficiency that meets a final emission limitation of 1,400 lb CO
The EPA of course realizes that the final standard of performance (1,400 lb CO
The BSER for newly constructed steam generating EGUs in the final rule is very similar to that in the proposal. In this final action, the EPA finds that a highly efficient new SCPC EGU implementing partial CCS to the degree necessary to achieve an emission of 1,400 lb CO
While the EPA does not find that IGCC technology—either alone or with implementation of partial CCS—is part of the BSER for new steam generating EGUs, we remain convinced that it is technically feasible (see Section V.E below) and believe that it represents a viable alternative compliance option that some project developers will consider to meet the final standard issued in this action. The EPA notes further that IGCC is available at reasonable cost (see Table 9 below), and involves use of an advanced technology. So, although the final standard reflects performance of a BSER which includes partial CCS, even in the instances that a compliance alternative might be utilized, that alternative would both result in emission reductions consistent with use of the BSER, and would reflect many of the underlying principles and attributes of the BSER (costs are both reasonable, not greatly dissimilar than BSER, no collateral adverse impacts on health or the environment, and reflects
In reaching the final standard of performance, the EPA is aware that at proposal, the agency stated that it was not “currently considering” a standard of performance as high as 1,400 lb CO
A more detailed discussion of the rationale for the final BSER determination and of other systems that were also considered is provided in Section V.P of this preamble.
The EPA has determined that, as proposed, the BSER for steam generating units that trigger the modification provisions is the modified unit's own best potential performance. However, as explained below, the final BSER determination and the scope of modifications to which the final standards apply differ in some important respects from what the EPA proposed.
The EPA proposed that the modified unit's best potential performance would be determined depending upon when the unit implemented the modification (
The final standards in this action do not depend upon when the modification commences, as long as it commences after June 18, 2014. We are establishing emission standards for large modifications in this rule and deferring at this time the setting of standards for small modifications.
In this final action, the EPA is issuing final emission standards for affected steam generating units that implement larger modifications that are consistent with the proposed BSER determination for those units. The final standard for those sources that implement larger modifications is a unit-specific emission limitation consistent with each modified unit's best one-year historical performance (during the years from 2002 to the time of the modification), but does not include the additional two percent reduction that was proposed in the January 2014 proposal.
In this action, the EPA is not finalizing standards for those sources that conduct smaller modifications and is withdrawing the proposed standards for those sources. See Section XV below.
A more detailed discussion of the rationale for the BSER determination and final standards is provided in Section VI of this preamble.
Consistent with our proposal, the EPA has determined that the BSER for reconstructed steam generating units is the most efficient demonstrated generating technology for these types of units (
The EPA is issuing final standards of performance for newly constructed, modified, and reconstructed affected steam generating units based on the degree of emission reduction achievable by application of the best system of emission reduction for those categories, as described above. The final standards are presented below in Table 6.
For newly constructed and reconstructed steam generating units and for modified steam generating sources that result in larger hourly increases of CO
Compliance with the final standard will be demonstrated by summing the emissions (in pounds of CO
For newly constructed steam generating units, we proposed two options for the compliance period. We proposed that a newly constructed source could choose to comply with a 12-operating-month standard or with a more stringent standard over an 84-operating-month compliance period, and we solicited comment on including an interim 12-operating-month standard (based on use of supercritical boiler technology, see 79 FR at 1448). We are not finalizing the proposed 84-operating-month compliance period option because the final standard of performance for newly constructed sources is less stringent than the proposed standard and because, as discussed in Section V below, we are identifying alternative compliance pathways for new steam generating EGUs. Specifically, we have concluded that there are unlikely to be significant issues with short-term variability during initial operation, in view of both the reduced numerical stringency of the standard, and the availability of compliance alternatives. The EPA notes that co-firing of natural gas can also serve as an interim means to reduce emissions if a new source operator believes additional time is needed to phase-in the operation of a CCS system. Therefore, the applicable final standards of performance for all newly constructed, modified, and reconstructed steam generating units must be met over a rolling 12-operating-month compliance period.
In the Clean Power Plan, which is a separate rulemaking under CAA section 111(d) published at the same time as the present rulemaking under CAA section 111(b), the EPA is promulgating emission guidelines for states to develop state plans regulating CO
In the discussion below, the EPA describes the rationale and justification of the BSER determination and the resulting final standards of performance for newly constructed steam generating units. We also explain why this determination is consistent with the constraints imposed by the EPAct05.
In evaluating the final determination of the BSER for newly constructed steam generating units, the EPA considered the factors for the BSER described above, looked widely at all relevant information and considered all the data, information, and comments that were submitted during the public comment period. We re-examined and updated the information that was available to us and concluded, as described below, that the final standard of 1,400 lb CO
In the sections that follow, we explain the technical configurations that may be used to implement BSER to meet the final standard, describe the operational flexibilities that partial CCS offers, and then provide the rationale for the final standard of performance. After that, we discuss, in greater detail, consideration of the criteria for the determination of the BSER. We describe why a highly efficient new SCPC EGU implementing partial CCS in the amount that results in an emission limitation of 1,400 lb CO
In the January 2014 proposal, the EPA proposed an emission limitation of 1,100 lb CO
For this final action, the EPA reexamined the BSER options available at proposal. Those options are: (1) Highly efficient generation without CCS, (2) highly efficient generation implementing partial CCS, and (3) highly efficient generation implementing full CCS. Consistent with our determination in the January 2014 proposal, we remain convinced that highly efficient generation (
As with the proposal, the EPA has determined the final BSER and corresponding emission limitation by appropriately balancing the BSER criteria and determining that the emission limitation is achievable. The final standard of performance of 1,400 lb CO
The proposed BSER was a highly efficient newly constructed steam generating EGU implementing partial CCS to an emission standard of 1,100 lb CO
As noted in Section III.H.3.g above, the EPA's determination of the BSER here includes review of recently constructed facilities and those planned or under construction to evaluate the control technologies being used and considered. Some of the projects discussed in the January 2014 proposal, and discussed here in this preamble, received or are receiving financial assistance under the EPAct05 (P.L. 109-58). This assistance may include financial assistance from the Department of Energy (DOE), as well as receipt of the federal tax credit for investment in clean coal technology under IRC Section 48A.
As noted above, the EPA interprets these provisions as allowing consideration of EPAct05 facilities provided that such information is not the sole basis for the BSER determination, and particularly so in circumstances like those here, where the information is corroborative but the essential information justifying the determinations comes from facilities and other sources of information with no nexus with EPAct05 assistance. In the discussion below, the EPA explains its reliance on other information in making the BSER determination for new fossil fuel-fired steam generating units. The EPA notes that information from facilities that did not receive any DOE assistance, and did not receive the federal tax credit, is sufficient by itself to support its BSER determination.
In this section, we describe a variety of facts that support our conclusion that the technical feasibility of post-combustion carbon capture is adequately demonstrated. First, we describe the technology of post-
Post-combustion capture processes remove CO
Additional information on post-combustion carbon capture—including process diagrams—can be found in a summary technical support document.
SaskPower's Boundary Dam CCS Project in Estevan, a city in Saskatchewan, Canada, is the world's first commercial-scale fully integrated post-combustion CCS project at a coal-fired power plant. The project fully integrates the rebuilt 110 MW coal-fired Unit #3 with a CO
Some commenters noted that, at 110 MW, the Boundary Dam Unit #3 is a relatively small coal-fired utility boiler and thus, in the commenters' view, does not demonstrate that such a system could be utilized at a much larger utility coal-fired boiler. However, there is nothing to indicate that the post-combustion system used at Boundary Dam could not be scaled-up for use at a larger utility boiler. In fact, the carbon capture system at Boundary Dam #3 is designed and constructed to implement “full CCS”—that is to capture more than 90 percent of the CO
A “slip-stream” is a portion of the flue gas stream that can be treated separately from the bulk exhaust gas. It is not an uncommon configuration for the flue gas from a coal-fired boiler to be separated into two or more streams and treated separately in different control equipment before being recombined to exit from a common stack.
In its study on the cost and performance of a range of carbon capture rates, the DOE/NETL determined that the slip-stream approach was the most economical for carbon capture of less than 90 percent of the total CO
The carbon capture system at Boundary Dam does not utilize the slip-stream configuration because it was designed to achieve more than 90 percent capture rates from the 110 MW facility. However, the same carbon capture equipment could be used to treat approximately 50 percent of the flue gas from a 220 MW facility—or 20 percent of the flue gas from a 550 MW facility. Thus, the equipment that is currently working very well (in fact, “better than expected”) at the Boundary Dam plant can be utilized for partial carbon capture at a much larger coal-fired unit without the need for further scale-up.
The experience at Boundary Dam is directly transferrable to other types of post-combustion sources, including those using different boiler types and those burning different coal types. There is nothing to suggest that the Shell CanSolv process would not work with other coal types and indeed, the latest NETL cost estimates assume that the capture technology would be used in a new unit using bituminous coal.
Commenters also noted that the Boundary Dam Unit #3 project received financial assistance from both the Canadian federal government and from the Saskatchewan provincial government. But the availability of—or the lack of—external financial assistance does not affect the technical feasibility of the technology. Commenters further characterized Boundary Dam as a “demonstration project”. These descriptors are beside the point. Regardless of what the project is called or how it was financed, the project clearly shows the technical feasibility of full-scale, fully integrated implementation of available post-combustion CCS technology, which in this case also appears to be commercially viable.
The EPA notes that, although there is ample additional information corroborating that post-combustion CCS is technically feasible, which we describe below, the performance at Boundary Dam Unit #3 alone would be sufficient to support that conclusion.
AES's coal-fired Warrior Run (Cumberland, MD) and Shady Point (Panama, OK) plants are both circulating fluidized bed (CFB) coal-fired power plants with carbon capture amine scrubbers developed by ABB/Lummus. The scrubbers were designed to process a slip-stream of each plant's flue gas. At the 180 MW Warrior Run Plant, a plant that burns bituminous coal, approximately 10 percent of the plant's CO
Since 1978, the Searles Valley Minerals soda ash plant in Trona, CA has used post-combustion amine scrubbing to capture approximately 270,000 metric tons of CO
Each of these processes indicate a willingness of industry to utilize available post-combustion technology for capture of CO
The EPA considers the experiences from the CCS projects described above, coupled with evidence that the design of CCS is well accepted (also described above) and the strong support that CCS has received from vendors and others (described below) to adequately demonstrate that post-combustion partial CCS is technically feasible. The EPA finds that additional projects, described next, provide more support for that conclusion. These projects received funding under EPAct05 from the Department of Energy, but that does not disqualify them from being considered. See Section III.H.3 above.
Petra Nova, a joint venture between NRG Energy Inc. and JX Nippon Oil & Gas Exploration, is constructing a commercial-scale post-combustion carbon capture project at Unit #8 of NRG's WA Parish generating station southwest of Houston, Texas. The project is designed to utilize partial CCS by capturing approximately 90 percent of the CO
The project was originally envisioned as a 60 MW slip-stream demonstration and received DOE Clean Coal Power Initiative (CCPI) funding (as provided in EPAct05) on that basis. The developers later expanded the project to the larger 240 MW slip-stream because of the need to capture greater volumes of CO
At 240 MW, the Petra Nova project will be the largest post-combustion carbon capture system installed on an existing coal-fueled power plant. The project will use for EOR or will sequester 1.6 million tons of captured CO
In 2014 project materials,
The technology has the potential to enhance the long-term viability and sustainability of coal-fueled power plants across the U.S. and around the world. . . . Post-combustion carbon capture is essential so that we can use coal to sustain our energy ecosystem while we begin reducing our carbon footprint.
According to NRG, the Petra Nova Carbon Capture Project will utilize “a proven carbon capture process,” jointly developed by Mitsubishi Heavy Industries, Ltd. (MHI) and the Kansai Electric Power Co., that uses a high-performance solvent for CO
The captured CO
The carbon capture system at WA Parish will utilize a slip-stream configuration. However, as noted, the system is designed to capture roughly 35 percent of the CO
Again, the experience at the WA Parish Unit #8 project will be directly transferable to post-combustion capture at a new utility boiler, even though WA Parish Unit #8 is an existing source that has been in operation for over 30 years. In fact, retrofit of such technology at an existing unit can be more challenging than incorporating the technology into the design of a new facility. The
In September 2009, AEP began a pilot-scale CCS demonstration at its Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a very large (1,300 MW) coal-fired unit that was retrofitted with Alstom's patented chilled ammonia CO
AEP, with assistance from the DOE, had planned to expand the slip-stream demonstration to a commercial scale, fully integrated demonstration at the Mountaineer facility. The commercial-scale system was designed to capture at least 90 percent of the CO
AEP also prepared a Front End Engineering & Design (FEED) Report,
In June 2011, Southern Company and Mitsubishi Heavy Industries (MHI) launched operations at a 25 MW coal-fired carbon capture facility at Alabama Power's Plant Barry. The facility, which completed the initial demonstration phase, captured approximately 165,000 metric tons of CO
Project participants have reported that “[t]he plant performance was stable at the full load condition with CO
As described earlier, the EPA does not find that IGCC technology—either alone or implementing partial CCS—is part of the BSER for newly constructed steam generating EGUs. However, as noted, there may be specific circumstances and business plans—such as co-production of chemicals or fertilizers, or capture of CO
Pre-combustion capture systems are typically used with IGCC processes. In a gasification system, the fuel (usually coal or petroleum coke) is heated with water and oxygen in an oxygen-lean environment. The coal (carbon), water and oxygen react to form primarily a mixture of hydrogen (H
In an IGCC system, the resulting syngas, after removal of the impurities, can be combusted using a conventional combustion turbine in a combined cycle configuration (
An emission standard that requires partial capture of CO
Most syngas streams are at higher pressure and can contain higher concentrations of CO
Additional information on pre-combustion carbon capture can be found in a summary technical support document.
Each day, the Dakota Gasification Great Plains Synfuels Plant uses approximately 18,000 tons of North Dakota lignite in a coal gasification process that produces syngas (a mixture of CO, CO
Capture of CO
Several commenters to the January 2014 proposal argued that the Great Plains Synfuels facility is not an EGU, that it operates as a chemical plant, and that its experience is not translatable to an IGCC using pre-combustion carbon capture technology. The commenters noted that the Dakota facility can be operated nearly continuously without the need to adjust operations to meet cyclic electricity generation demands. In the January 2014 proposal, the EPA had noted that, while the facility is not an EGU, it has significant similarities to an IGCC and the implementation of the pre-combustion capture technology would be similar enough for comparison. See 79 FR at 1435-36 and n. 11. We continue to hold this view.
As explained above, in an IGCC gasification system, coal (or petroleum coke) is gasified to produce a synthesis gas comprised of primarily CO, H
The Dakota Gasification process bears essential similarities to the just-described IGCC gasification system. As with the IGCC gasification system, the Dakota Gasification facility gasifies coal (lignite) to produce a syngas which is then shifted to increase the concentration of CO
There are some international projects that are in various stages of development that indicate confidence by developers in the technical feasibility of pre-combustion carbon capture. Summit Carbon Capture, LLC is developing the Caledonia Clean Energy Project, a proposed 570-megawatt IGCC plant with 90 percent CO
The China Huaneng Group—with multiple collaborators, including Peabody Energy, the world's largest private sector coal company—is building the 400 MW GreenGen IGCC
Vattenfall and Nuon's pilot project in Bugennum, The Netherlands involves carbon capture from coal- and biomass-fired IGCC plants. It has operated since 2011.
Approximately 100 tons of CO
Emirates Steel Industries is expected to capture approximately 0.8Mt of CO
The Uthmaniyah CO
The experience of the Dakota Gasification facility, coupled with the descriptions of the technology in the literature, the statements from vendors, and the experience of facilities internationally, are sufficient to support our determination that the technical feasibility of CCS for an IGCC facility is adequately demonstrated. The experience of additional facilities, described next, provides additional support.
Coffeyville Resources Nitrogen Fertilizers, LLC, owns and operates a nitrogen fertilizer facility in Coffeyville, Kansas. The plant began operation in 2000 and is the only one in North America using a petroleum coke-based fertilizer production process. The petroleum coke is generated at an oil refinery adjacent to the plant. The petroleum coke is gasified to produce a hydrogen rich synthetic gas, from which ammonia and urea ammonium nitrate fertilizers are subsequently synthesized.
As a by-product of manufacturing fertilizers, the plant also produces significant amounts of CO
At least one commenter suggested that the cost and complexity of carbon capture from these and other industrial projects was significantly decreased because the sources already separate CO
Southern Company's subsidiary Mississippi Power has constructed the Kemper County Energy Facility in Kemper County, MS. This is a 582 MW IGCC plant that will utilize local Mississippi lignite and includes a pre-combustion carbon capture system to reduce CO
The Kemper County IGCC Project will capture and compress approximately 65% of the Plant's CO
Thus, Mississippi Power believes that, because the Selexol
The Texas Clean Energy Project (TCEP), a 400 MW IGCC facility located near Odessa, Texas will capture 90 percent of its CO
In this section, we describe additional information that supports our determination that CCS is adequately demonstrated to be technically feasible. This includes performance guarantees from vendors, public statements from industry officials, and review of the literature.
The D.C. Circuit made clear in its first cases concerning CAA section 111 standards, and has affirmed since then,
Linde and BASF offer performance guarantees for carbon capture technology. The two companies are jointly marketing new, advanced technology for capturing CO
The captured carbon dioxide can be used commercially for example for EOR (enhanced oil recovery) or as a building block for the production of urea. Alternatively it can be stored underground as a carbon abatement measure. [. . .] The PCC (Post-Combustion Capture) technology
The alliance between Linde, a world-leading gases and engineering company and BASF, the chemical company, offers great benefits [. . .] Complete capture plants including CO
In addition, other well-established companies that either offer technologies that are actively marketed for CO
Fluor has also published an article titled “Commercially Available CO
Mitshubishi Heavy Industries (MHI) offers a CO
In addition, Shell has developed the CANSOLV CO
At least one commenter suggested that it is unlikely that any vendor is willing or able to provide guarantees of the performance of the system as a whole, arguing that this shows the system isn't adequately demonstrated.
Climate change mitigation options—including CCS—are the subject of great academic interest, and there is a large body of academic literature on these options and their technical feasibility. In addition, other research organizations (
The discussion above of vendor guarantees, positive statements by industry officials, and the academic literature supports the EPA's determination that partial CCS is adequately demonstrated to be
For example, Southern Company's Mississippi Power has stated that, because the Selexol
The carbon capture process being utilized for the Kemper County IGCC is a commercial technology referred to as Selexol
And . . .
The carbon capture equipment and processes proposed in this project have been in commercial use in the chemical industry for decades and pose little technology risk.
Similarly, in an AEP Second Quarter 2011 Earnings Conference Call, Chairman and CEO Mike Morris said of the Mountaineer CCS project:
We are encouraged by what we saw, we're clearly impressed with what we learned, and we feel that we have demonstrated to a certainty that the carbon capture and storage is in fact viable technology for the United States and quite honestly for the rest of the world going forward.
Some commenters have claimed that CCS technology is not technically feasible, and some further assert that vendors do not offer performance guarantees. For example, Alstom commented:
The EPA referenced projects fail to meet the ‘technically feasible' criteria. These technologies are not operating at significant scale at any site as of the rule publication. We do not support mandating technology based on proposed projects (many of which may never be built).
As discussed above, vendors do in fact offer performance guarantees. We further note that, as noted above, Boundary Dam Unit #3 is a full-scale project that is successfully implementing full CCS with post-combustion capture, and Dakota Gasification is likewise a full-scale commercial operation that is successfully implementing pre-combustion CCS technology. Moreover, as we explain above, this technology and performance is transferable to the steam electric generating sector. In addition, as noted above, technology providers and technology end users have expressed confidence in the availability and performance of CCS technology.
Some commenters asserted that CCS cannot be considered the BSER because it is not commercially available. There is no requirement, as part of the BSER determination, that the EPA finds that the technology in question is “commercially available.” As we described in the January 2014 proposal, the D.C. Circuit has explained that a standard of performance is “achievable” if a technology or other system of emission reduction can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard, and that there is no requirement that the technology “must be in routine use somewhere.” See
Commenters maintained that the EPA can only show that a BSER is “adequately demonstrated” using operating data from the technology or system of emission reduction itself. This is mistaken. Since the very inception of the CAA section 111 program, courts have noted that “[i]t would have been entirely appropriate if the Administrator had justified the standard, not on the basis of tests on existing sources or old test data in the literature, but on extrapolations from this data, on a reasoned basis responsive to comments, and on testimony from experts and vendors . . . .”
Our prior decisions relating to technology-forcing standards are no bar to this conclusion. We recognize here, as we have recognized in the past, that an agency may base a standard or mandate on future technology when there exists a rational connection between the regulatory target and the presumed innovation.
In a related argument, other commenters stated that a system cannot be adequately demonstrated unless all of its component parts are operating together.
The short of it is that the “EPA does have authority to hold the industry to a standard of improved design and
Commenters maintained that the EPA had no basis for maintaining that pilot and demonstration plant operations showed that CCS was adequately demonstrated. This is mistaken. In a 1981 decision,
Most obviously, the final standard reflects experience of full-scale operation of post-combustion carbon capture. Pre-combustion carbon capture is likewise demonstrated at full-scale. Second, the record explains in detail how CCS can be implemented at full-scale. The NETL cost and performance reports, indeed, contain hundreds of pages of detailed, documented explanation of how CCS can be implemented at full-scale for both utility boiler and IGCC facilities. See, for example, the detailed description of the following systems projected to be needed for a new supercritical PC boiler to capture CO
It is important to note that, while some commenters challenged the EPA's use of costs in the DOE/NETL cost and performance reports, commenters did not challenge the technical methodology in the work.
In addition, the AEP FEED study indicates how the development scale post-combustion CCS could be successfully scaled up to full-scale operation. See Section V.D.3.b above.
Tenaska Trailblazer Partners, LLC also prepared a FEED study
Much has been written about the complexities of adding CCS systems to fossil fuel-fired power plants. Some of these statements come from high government officials. Some commenters argued that the EPA minimized—or even ignored—these publically voiced concerns in the discussion presented in the January 2014 proposal. On the contrary, the EPA has not minimized or ignored these complexities, but it is important to realize that most of these statements come in a different context: Namely, implementing full CCS, or retrofitting CCS onto existing power plants. For example, in the Final Report of the President's CCS Task Force, it was noted that “integration of CCS technologies with the power cycle at generating plants can present significant cost and operating issues that will need to be addressed to facilitate widespread, cost-effective deployment of CO
Concerns regarding “operating issues” are also often associated with implementation of full CCS—and often with implementation of full CCS as a retrofit to an existing source. Implementation of CCS at some existing sources may be challenging because of space limitations. That should not be an issue for a new facility because the developer will need to ensure that adequate space is available during the design of the facility. Constructing CCS technology at an existing facility can be challenging even if there is adequate space because the positioning of the equipment may be awkward when it must be constructed to fit with the existing equipment at the plant. Some commenters noted the challenges of diverting steam from the plant's steam cycle. Again, that is primarily an issue with full CCS implementation as a retrofit to an existing source. Consideration of steam requirements for solvent regeneration can be factored into the design of a new facility. We also note that issues of integration with the plant's steam cycle are less challenging when implementing partial CCS.
Some commenters noted conclusions and statements from the CCS Task Force report as contradictory to the EPA's determination of that partial CCS is technically feasible and adequately demonstrated. However, the EPA mentioned in the January 2014
Thus, the EPA has provided an ample record supporting its finding that partial CCS is feasible at full-scale. As in
CAA section 111(a) defines “standard of performance” as an emission standard that reflects the best system of emission reduction that is adequately demonstrated, “taking into account [among other things] the cost of achieving such reduction.” Based on consideration of relevant cost metrics in the context of current market conditions, the EPA concludes that the costs associated with the final standard are reasonable.
In reaching this determination, the EPA considered a host of different cost metrics, each of which illuminated a particular aspect of cost consideration, and each of which demonstrated that the costs of the final standard are reasonable. The EPA evaluated capital costs on a per-plant basis, responding to public comment that noted the particular significance of capital costs for coal-fired EGUs. As in the proposal, the EPA also considered how the standard would affect the LCOE for individual affected EGUs as well as national, overall cost impacts of the standard. The EPA found that the anticipated cost impacts are similar to those in other promulgated NSPS—including for this industry—that have been upheld by the D.C. Circuit. The costs are also comparable to those of other base load technologies that might be selected on comparable energy portfolio diversity grounds. Finally, the EPA does not anticipate any significant overall nationwide costs or cost impacts on consumers because projected new generating capacity is expected to meet the standards even in the baseline. Accordingly, after considering costs from a range of different perspectives, the EPA concludes that the costs of the final standard are reasonable.
At proposal, the EPA evaluated the costs of new coal-fired EGUs implementing full (90 percent) and partial CCS. The EPA compared the predicted LCOE of those units against the LCOE of other new dispatchable technologies often considered for new base load power with fuel diversity, primarily including a new nuclear plant, as well as a new biomass-fired EGU. See 79 FR at 1475-78. The levelized cost for a new steam EGU implementing full CCS was higher than that of the other non-NGCC dispatchable technologies, and we did not propose to identify a new steam EGU implementing full CCS as BSER on that basis. Id. at 1477. The EPA proposed that a standard of performance of 1,100 lb CO
In addition, the EPA proposed that the costs to implement partial CCS were reasonable because a segment of the industry was already accommodating them.
As explained above, CAA section 111(a) directs the EPA to “tak[e] into account the cost” of achieving reductions in determining if a particular system of emission reduction is the best that is adequately demonstrated. The statute does not provide further guidance on how costs should be considered, thus affording the EPA considerable discretion in choosing a means of cost consideration. In addition, it should be noted that in evaluating the reasonableness of costs, the D.C. Circuit has upheld application of a variety of metrics, such as the amount of control costs or product price increases. See Section III.H.3.(b).(1) above.
Following the directive of CAA section 111(a) and applicable precedent, the EPA evaluated relevant metrics and context in considering the reasonableness of the regulation's costs. The EPA's findings demonstrate that the costs of the selected final standard are reasonable.
The EIA projects that few new coal-fired EGUs will be constructed over the coming decade and that those that are built will apply CCS, reflecting the broad consensus of government, academic, and industry forecasters.
The EIA's projection is confirmed by an examination of Integrated Resource Plans (IRPs) contained in a TSD in the docket for this rulemaking. IRPs are used by utilities to plan operations and investments in both owned generation and power purchase agreements over long time horizons. Though IRPs do not demonstrate a utility's intent to pursue a particular generation technology, they do indicate the types of new generating technologies that a utility would consider for new generating capacity. The EPA's survey of recent IRPs demonstrates that across the nation, utilities are not actively considering constructing new coal-fired generation without CCS in the near term.
Accordingly, construction of new uncontrolled coal-fired generating capacity is not anticipated in the near term, even in the absence of the standards of performance we are finalizing in this rule, except perhaps in certain limited circumstances.
In particular, commenters suggested that some developers might choose to build a new coal-fired EGU, despite its not being cost competitive, in order to achieve or maintain “fuel diversity.” Fuel diversity could provide important value by serving as a hedge against the possibility that future natural gas prices will far exceed projected levels.
Public announcements, including IRPs, confirm that utilities are interested in technologies that could provide or preserve fuel diversity within generating fleets. The Integrated Resource Plan TSD
In addition, the EPA recognizes that there may be interest in constructing a new combined-purpose coal-fired facility that would generate power as well as produce chemicals or CO
As demonstrated below, the agency carefully considered the reasonableness of costs in identifying a standard that allows a path forward for such projects and rejects more stringent options that would impose potentially excessive costs. In fact, based on this careful consideration of costs, the EPA is finalizing a substantially lower cost standard than the one we proposed. At the same time, we note the unusual circumstances presented here, where the record, and indeed simple consideration of electricity market economics, demonstrates that non-economic factors such as fuel diversity are likely to drive any construction of new coal-fired generation. See also RIA chapter 4 (documenting that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this rule even in its absence, primarily NGCC units, because of existing and expected market conditions). Under these circumstances, the EPA's consideration of costs takes into account that higher costs can be viewed as reasonable when costs are not a paramount factor in new coal capacity decisions. At the same time, the EPA acknowledges and agrees with the public comments that such an argument, left unconstrained, could justify any standard and obviate all cost considerations.
As noted above, CAA section 111 does not mandate any particular method for evaluating costs, leaving the EPA with significant discretion as to how to do so. One method is to consider the incremental capital costs required for a unit to achieve the standard of performance.
The EPA included information on capital cost at proposal and, as discussed further below, the LCOE metric relied upon at proposal and in this final rulemaking incorporates and fully reflects capital costs.
Prior new source performance standards for new fossil steam generation units have had significant—yet manageable—impacts on the capital costs of construction. The EPA estimated that the costs for the 1971 NSPS for coal-fired EGUs were $19M for a 600 MW plant, consisting of $3.6M for particulate matter controls, $14.4M for sulfur dioxide controls, and $1M for nitrogen oxides controls, representing a 15.8 percent increase in capital costs
In reviewing the 1978 NSPS for coal-fired EGUs, the D.C. Circuit recognized that “EPA estimates that utilities will have to spend tens of billions of dollars by 1995 on pollution control under the new NSPS” and that “[c]onsumers will ultimately bear these costs.”
The cost and investment impacts of the 1978 NSPS on electric utilities were subsequently evaluated in a 1982 Congressional Budget Office (CBO) retrospective study.
The study retrospectively confirmed the EPA's conclusion that imposition of these costs was reasonable, finding that “utilities with commitments to pollution control tend to fare no better and no worse than all electric utilities in general.”
In NSPS standards for other sectors, the EPA's determination that capital cost increases were reasonable has similarly been upheld. In
The capital cost impacts incurred under these prior standards are comparable in magnitude on an individual unit basis to those projected for the present standard. We predict that the incremental costs of control for a new highly efficient SCPC unit to meet the final emission limitation of 1,400 lb CO
By comparison, a SCPC that co-fires with natural gas to meet the final standard of 1,400 lb CO
As in the proposal, the EPA also considered the reasonableness of costs by evaluating the LCOE associated with the final standard. The LCOE is a commonly used economic metric that takes into account all costs to construct and operate a new power plant over an assumed time period and an assumed capacity factor. The LCOE is a summary metric, which expresses the full cost of generating electricity on a per unit basis (
As previously mentioned, at proposal the EPA relied on LCOE projections for fossil fuel-fired EGUs (with and without CCS) from DOE/NETL reports detailing the results of studies evaluating the costs and performance of such units. For non-fossil dispatchable generating sources, the EPA relied on LCOE projections from EIA AEO 2013. For this final action, the EPA is relying on updated costs from the same sources. The NETL has provided updated cost and performance information in recently published revisions of reports used in the January 2014 proposal.
Using information from those reports, the DOE/NETL prepared a separate report summarizing a study that evaluated the cost and performance of various plants designed to meet a range of CO
The LCOE of a power plant source is calculated with the expected lifetime and average capacity factor, and represents the average cost of producing a megawatt-hour (MWh) of electricity over the expected lifetime of the asset.
The LCOE incorporates all specified costs, and therefore is dependent on the project's capital costs, the fixed and variable operating and maintenance (O&M) costs, the fuel costs, the costs to finance the project, and finally on the assumed capacity factor.
The utility industry and electricity sector regulators often use levelized costs as a summary measure for comparing the cost of different potential generating sources. Use of the LCOE as a comparison measure is appropriate where the facilities being compared would serve load in a similar manner.
The value of generation, as reflected in the wholesale electricity price, can vary seasonally and over the course of a day. In addition, electricity generation technologies differ on dimensions other than just cost, such as ramping efficiency, intermittency, or uncertainty in future fuel costs. These other factors are also important in determining the value of a particular generation technology to a firm, and accordingly cost comparisons between two different technologies are most appropriate and insightful when the technologies align along these other dimensions. Isolating a comparison of technologies based on their LCOE is appropriate when they can be assumed to provide similar services and similar values of electricity generated.
As we indicated in the proposal, we evaluated publicly available IRPs and other available information (such as public announcements) to determine the types of technologies that utilities are considering as options for new generating capacity.
With those factors in mind, the 2014 Plan presents two paths forward for resource expansion: a Base Plan, designed using least-cost planning methods and consistent with the requirements of Rule R8-60 for utility plans to provide “reliable electric utility service at least cost over the planning period;” and a Fuel Diversity Plan, which includes a broader array of low or zero-emissions options. While the Fuel 2 Diversity Plan currently represents a higher cost option at today's current and projected commodity prices, its resource mix provides the important benefits of greater fuel diversity and lower carbon intensity. Therefore, the Company will continue reasonable development of the more diverse and lower carbon intensive options in the Fuel Diversity Plan and will be ready to implement them as conditions warrant. . . . The Fuel Diversity Plan places a greater reliance on generation sources with little or no carbon emissions and is less reliant on natural gas. While following the resource expansion scenario in the least-cost Base Plan, the Company will continue evaluation and reasonable development efforts for the following projects identified in the Fuel Diversity Plan. These include:
Continued development of a third nuclear reactor at North Anna Power Station, using reactor technology supplied by GE-Hitachi Nuclear Energy Americas LLC. While the Company has made no final commitment to building this unit, it recognizes the many operational and environmental benefits of nuclear power and continues to actively develop the project. Our customers have benefitted from the existing nuclear fleet for many years now, and they will continue to benefit from the existing fleet for many years in the future. A final decision on construction of North Anna Unit 3 will not be made until after the Company receives a Combined Operating License or COL from the U.S. Nuclear Regulatory Commission, now expected in 2016. The Fuel Diversity Plan includes the addition of North Anna Unit 3's 1,453 megawatts of zero-emissions generation by 2028. If constructed, the project would provide a dramatic boost to the regional economy.
Additional reliance on renewable energy, including 247 megawatts of onshore wind capacity at sites in western Virginia and a 12 megawatt offshore wind demonstration project by 2018.
An additional 559 megawatts of nameplate solar capacity, including several new Company-owned photovoltaic CPV) installations. Solar PV costs have declined significantly in recent years, making utility-scale solar much more cost-effective than distributed solar, and continuing technological development, in which the Company is participating, may allow it to become a more cost-effective source of intermittent generation in the future.cover letter for 2014 IRP—
“We are considering nuclear, coal and natural gas,” said Ken Anderson, general manager of Tri-State at a conference in October [2010], a position that Tri-State representatives say remains. “We will pick our technology once policy certainty comes about,” he added. . . . Longer-term forecasts are based on assumptions that may or may not prove well-founded. Because of this uncertainty, Tri-State believes it must retain options for all fuels and technologies.
“We will not take anything off the table,” [Tri-State spokesman Lee] Boughey said. That includes coal. “Coal is an affordable and plentiful resource, but it does come with challenges—and we are
Thus, in both the proposal and in this final rule, the EPA is comparing the LCOE of technologies that would be reasonably anticipated to be designed, constructed, and operated for a similar purpose—that is, to provide dispatchable base load power that provides fuel diversity by relying on a fuel source other than natural gas. In contrast, it may not be appropriate to compare the LCOE for a base load coal-fired plant with that of a peaking natural gas-fired simple cycle turbine. Similarly, it may not be appropriate to compare LCOE for dispatchable technologies (
An examination of the LCOE of analogous sources of base load, dispatchable power shows that the final standard's LCOE is comparable to that of other sources, as shown in Table 8 below. As mentioned earlier and discussed in further detail below, these estimates rely most heavily on DOE/NETL cost projections for fossil fuel generating technologies and on the updated EIA AEO 2015 for non-fossil generation technologies. Recent estimates from Lazard
As shown in Table 8, we project that the LCOE for new fossil steam capacity meeting the final 1,400 lb CO
As previously mentioned, the DOE/NETL assumed conventional financing
This approach is in contrast to that taken by the EIA which applies a 3-percentage-point cost of capital premium (the `climate uncertainty adder') to non-capture coal plants to reflect the market reaction to potential future GHG regulation.
Under current and anticipated market conditions, power providers that are considering costs alone in choosing a fuel source for new intermediate or base load generation will choose natural gas because of its competitive current and projected price. However, as noted in Section V.H.3, public IRPs indicate that utilities are considering and selecting technologies that could provide or preserve fuel diversity within generating fleets. For example, utilities have been willing to pay a premium for nuclear power in certain circumstances, as indicated by the recent new constructions of nuclear facilities and by IRPs that include new nuclear generation in their plans. In general, fossil steam and nuclear generation each can provide dispatchable, base load power while also maintaining or increasing fuel diversity.
We further note a number of conservative elements of the costs we used in making this comparison. In particular, these estimates include the highest value in the projected range of potential costs for partial CCS. They do not reflect revenues which can be generated by selling captured CO
As noted above, an assessment of national costs is also an appropriate means of evaluating the reasonableness of costs under CAA section 111. See
The EPA considered the regulation's overall costs and economic impacts as part of its RIA. The RIA demonstrates that these costs would be negligible and that the effects on electricity rates and other market indicators would similarly be minimal.
These results are driven by the existing market context for fossil-steam generation. Even in the absence of the standards of performance for newly constructed EGUs, substantial new construction of uncontrolled fossil steam units is not anticipated under existing prevailing and anticipated future economic conditions. Modeling projections from government, industry, and academia anticipate that few new fossil steam EGUs will be constructed over the coming decade and that those that are built would have CCS.
In its RIA, the EPA considered the overall costs of this regulation in the context of these prevailing market trends. Because of the expectation of no new fossil steam generation, the RIA projects that this final rule will result in negligible costs overall on owners and operators of newly constructed EGUs by 2022.
In comparison, courts have upheld past regulations that imposed substantial overall costs in order to protect against uncontrolled emissions. As noted above, in
The projected total incremental capital costs associated with the standard we are finalizing in this rule are dramatically lower than was the case for this prior standard, as well as other prior standards summarized previously. For example, when the standard at issue in
Commenters stated that the cost provision in CAA section 111(a)(1) does not authorize the EPA to consider the nationwide costs of a system of emission reduction in lieu of considering the cost impacts for individual new plants. In this rule, we
However, as noted earlier, for a variety of reasons, some companies may consider coal-fired steam generating units that the modeling does not anticipate. Thus, in Chapter 5 of the RIA, we also present an analysis of the project-level costs of a newly constructed coal-fired steam generating unit with partial CCS that meets the requirements of this final rule alongside the project-level costs of a newly constructed coal-fired unit without CCS. This analysis in RIA chapter 5 indicates that the quantified benefits of the standards of performance would exceed their costs under a range of assumptions.
As required under Executive Order 12866, the EPA conducts benefit-cost analyses for major Clean Air Act rules, and has done so here. While such analysis can help to inform policy decisions, as permissible and appropriate under governing statutory provisions, the EPA does not use a benefit-cost test (
While the EPA believes, as detailed above, that there is sufficient evidence to show that the final standards of performance for new steam generating units can be met at a reasonable cost, we also note that there are potential opportunities to further reduce compliance costs. We believe that, in most cases, the actual costs will be less than those presented earlier.
As explained in more detail in the following subsection, a new utility boiler can meet the final standard of performance by co-firing with natural gas. Some project developers may choose to utilize natural gas co-firing as a means of delaying, rather than avoiding, implementation of partial CCS. Developers can also choose to install IGCC with a small amount of natural gas co-firing at costs within the range of SCPC with partial CCS, although slightly higher.
The EPA also notes that new units that capture CO
In some instances, the costs of CCS may be defrayed by grants or other benefits provided by federal or state governments. The need for subsidies to support emerging energy systems and new control technologies is not unusual. Each of the major types of energy used to generate electricity has been or is currently being supported by some type of government subsidy such as tax benefits, loan guarantees, low-cost leases, or direct expenditures for some aspect of development and utilization, ranging from exploration to control installation. This is true for fossil fuel-fired, as well as nuclear-, geothermal-, wind-, and solar-generated electricity. As stated earlier, the EPA considers the costs of partial CCS at a level to meet the final standard of performance to be reasonable even without considering these opportunities to further reduce implementation and compliance costs. We did not in the proposal—and we do not here in this final action—rely on any cost reduction opportunities to justify the costs of meeting the standard as reasonable, but again note the conservative assumptions embodied in our assessment of compliance costs.
Although the EPA has determined that implementation of partial CCS at an emission limitation of 1,400 lb CO
At the final emissions limitation of 1,400 lb CO
Natural gas co-firing has long been recognized as an option for coal-fired boilers to reduce emissions of criteria and hazardous air pollutants. EPRI sponsored a study to assess both technical and economic issues associated with natural gas co-firing in coal-fired boilers.
Higher levels of natural gas co-firing can be met by utilizing supplemental gas co-firing (either alone or along with natural gas reburning). This involves the simultaneous firing of natural gas and pulverized coal in a boiler's primary combustion zone. Others have also evaluated configurations that would allow coal-fired units to utilize natural gas.
A 2013 article entitled “Utility Options for Leveraging Natural Gas”
Utility owners of coal-fired power stations that wish to balance their exposure to coal-fired generation with additional natural gas-fired generation have several options to consider. The four most practical options are co-firing coal and gas in the same boiler, converting the coal-fired boiler to gas-only operation, repowering the coal plant with natural gas-fired combustion turbines, or replacing the coal plant with a combined cycle plant. [. . .] Co-firing is the lowest-risk option for substituting gas use for coal.
The EPA examined compliance costs for a new steam generating unit to meet the final standard of performance using natural gas co-firing and compared those costs to the estimated costs of meeting the
The EPA thus again notes that the cost assumptions it is making in its BSER determination are conservative. That is, by costing partial CCS as BSER, the EPA may be overestimating actual compliance costs since there exist other less expensive means of meeting the promulgated standard.
Notwithstanding that costs for a SCPC to meet the standard would be lower if it co-fired with natural gas, we have not identified that compliance alternative as BSER because we believe that new coal-fired steam electric generating capacity would be built to provide fuel diversity, and burning substantial amounts of natural gas would be contrary to that objective. In addition, this choice would not promote use of advanced pollution control technology. New IGCC has costs which are comparable to SCPC, as does IGCC with natural gas co-firing,
The EPA reasonably expects that the costs of CCS will decrease over time as the technology becomes more widely deployed. Although, for the reasons that have been noted, we consider the current costs of CCS to be reasonable, the projected decrease in those costs further supports their reasonableness. The D.C. Circuit case law that authorizes determining the “best” available technology on the basis of reasonable future projections supports taking into account projected cost reductions as a way to support the reasonableness of the costs.
We expect the costs of CCS technologies to decrease for several reasons. We expect that significant additional knowledge will be gained from deployment and operation of the new coal-fired generation facilities that are either operating or are nearing completion. These would include the Boundary Dam Unit #3 facility, the Petra Nova WA Parish project, and the Kemper County IGCC facility. The operators of the Boundary Dam Unit #3 are considering construction of additional CCS units and have projected that the next units could be constructed at a cost of at least 30 percent less than that at Unit #3.
To facilitate the transfer of the technology and to accelerate development of carbon capture technology, SaskPower has created the CCS Global Consortium.
The DOE also sponsors testing at the National Carbon Capture Center (NCCC). The NCCC—located at Southern Company's Plant Gaston in Wilsonville, AL—provides first-class facilities to test new capture technologies for extended periods under commercially representative conditions with coal-derived flue gas and syngas.
We expect continued additional cost reductions to come from knowledge gained from continued operation of non-power sector industrial projects which, as we have discussed, are informative in transferring the technology to power sector applications. We expect the on-going research and development efforts—such as those sponsored by the DOE/NETL.
Significant reductions in the cost of CO
Geologic storage options include use of CO
In its consideration of the costs associated with the final standard, the EPA considered a range of different cost metrics, each with its individual strengths and weaknesses. As discussed above, each metric supports the EPA's conclusion that the costs of the final standard are reasonable.
In this section, we review the comments received on assessing cost reasonableness and specific cost metrics. We explain how these comments informed our consideration of different metrics and cost reasonableness in general.
As noted, CAA section 111(a) directs the EPA to consider “cost” in determining if the BSER is adequately demonstrated. It does not provide further guidance as to how costs are to be considered, thus affording the EPA considerable discretion to choose a reasonable means of cost consideration. See,
Commenters also argued that the choice of LCOE as a cost metric masked consideration of the considerable capital costs associated with CCS. The EPA disagrees with this contention. The LCOE does not mask consideration of capital costs. Rather, as explained at V.H.5 above, LCOE is a summary metric that expresses the full cost (
The EPA certainly does not minimize that project developers must take capital costs into consideration, and as discussed in Section V.H.4 above, the EPA accordingly has considered direct capital costs here as part of its assessment and found those costs to be reasonable. In addition, the EPA notes that its comparison of the marginal impacts from an individual illustrative facility's compliance with the standard, discussed in detail above and in the RIA Chapter 5, took into account the marginal capital costs that would be incurred by an individual facility.
According to EIA,
Some commenters maintained that even if LCOE was a proper cost metric, the comparison with the costs of a new nuclear power plant is improper because nuclear itself is a highly expensive technology. The EPA disagrees. The comparison is appropriate and valid because, as discussed at V.H.3 above, under current and foreseeable economic conditions affecting the cost of new fossil steam generation and new nuclear generation relative to the cost of new natural gas generation, neither new nuclear power nor fossil steam generation are competitive with new natural gas if evaluated on the basis of LCOE alone. Nonetheless, both are important potential alternatives to natural gas power for those interested in dispatchable base load power that maintains or increases fuel diversity. As shown in a survey of recent IRP filings in the docket
In the January 2014 proposal, the EPA relied mostly on the cost projections for new fossil fuel-fired generating sources that were informed by cost studies conducted by DOE/NETL. The EPA relied on the EIA's AEO 2013 projections for non-fossil based generating sources (
The DOE/NETL “Cost and Performance Baselines for Fossil Energy Plants” are a series of studies conducted by NETL to establish estimates for the cost and performance of combustion and gasification based power plants with and without CO
The EPA relied on those sources because the NETL studies are the most comprehensive and transparent of the available cost studies and NETL has a reputation in the power sector industry for producing high quality, reliable work.
The cost estimates were indicated by DOE/NETL to carry an accuracy of −15 percent to +30 percent on the capital costs, consistent with a AACE Class 4 cost estimate—
For the final standard, the EPA made particular use of the most recent NETL cost estimates for post-combustion CCS, which reflect up-to-date vendor quotes and incorporate the post-combustion capture technology—the Shell Cansolv amine-based process—that is being utilized at the Boundary Dam Unit #3 facility.
A variety of government, industry and academic groups routinely conduct studies to estimate costs of new generating technologies. These studies use techno-economic models to predict the cost to build a new generating facility at some point in the future. These studies often use levelized cost of electricity (LCOE) to summarize costs and to compare the competiveness of the different generating technologies.
A variety of groups have recently published LCOE estimates for new dispatchable generating technologies. Those are shown below in Table 10. The table shows LCOE projections from the EPA's January 2014 proposal, from studies conducted by the Electric Power Research Institute (EPRI),
The Global CCS Institute
The fact that these various groups have conducted independent studies and that the results of those independent studies are reasonably consistent with the estimates of DOE/NETL are further indications that the DOE/NETL cost estimates are reasonable.
The LCOE
The EIA cost estimates include a climate uncertainty adder (CUA)—represented by a three percent increase to the weighted average cost of capital—to certain coal-fired capacity types. The EIA developed the CUA to address inconsistencies between power sector modeling absent GHG regulation and the widespread use of a cost of CO
Information from vendors of CCS technology also supports the reliability of the cost estimates the EPA is using here.
Summit Carbon Capture's primary business is large-scale carbon capture from power and other industrial projects and use of the captured CO
Summit is also interested in potentially retrofitting CCS onto existing coal-fired plants for the purpose of capturing CO
In June 2012, Alstom Power released a report entitled “Cost assessment of fossil power plants equipped with CCS under typical scenarios”.
The EPA notes that in its public comments, Alstom maintained that “no CCS projects that would [sic] be considered cost competitive in today's energy economy.”
For the January 2014 proposal the EPA chose to rely on the EIA AEO 2013 cost projections for non-fossil based generation. The AEO presents long-term annual projections of energy supply, demand, and prices focused on U.S. energy markets. The predictions are based on results from EIA's National Energy Modeling System (NEMS). The AEO costs are updated annually, they are highly scrutinized, and they are widely used by those involved in the energy sector.
In the January 2014 proposal, the EPA presented LCOE costs for new non-fossil dispatchable generation (see 77 FR 1477, Table 7) from the AEO 2013. Those costs were updated as part of the AEO 2015 release. The estimated cost for all of these technologies decreased from AEO 2013 to AEO 2014 and AEO 2015. This was due to changes in the interest rates that resulted in lower financing costs relative to those used the AEO 2013.
As previously mentioned, the projected costs are dependent upon a range of assumptions including the projected capital costs, the cost of financing the project, the fixed and variable O&M costs, the projected fuel costs, and incorporation of any incentives such as tax credits or favorable financing that may be available to the project developer. There are also regional or geographic differences that affect the final cost of a project. The LCOE projections in this final action are not intended to provide an absolute cost for a new project using any of these respective technologies. Large construction projects—as these would be—would be subjected to detailed cost analyses that would take into consideration site-specific information and specific design details in order to determine the project costs.
The DOE/NETL noted that the cost estimates from their studies carry an accuracy in the range of −15 percent to +30 percent, which is consistent with a “feasibility study” level of design. They also noted that the value of the studies lies “not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated.”
The EIA AEO 2015 presented LCOE costs as a single point estimate representing average nationwide costs and separately as a range to represent the regional variation in costs. In order to compare the fossil fuel generation technologies from the NETL studies with the cost projections for non-fossil dispatchable technologies from EIA AEO 2015, we assume that the EIA studies would carry a similar level of uncertainty (
Although we are relying on cost estimates drawn from techno-economic models, we recognize that there are a few steam electric plants that include CCS that have been built, or are being constructed. Some information about the costs (or cost-to-date) for these projects is known. We discuss in this section the costs at facilities which have installed or are installing CCS, why the EPA does not consider those costs to be reasonably predictive of the costs of the next new plants to be built, and why the EPA considers that the next new plants will have lower costs along the lines predicted by NETL.
The Boundary Dam Unit #3 facility utilizing post-combustion capture from Shell Cansolv is now operational. Petra Nova, a joint venture between NRG Energy Inc. and JX Nippon Oil & Gas Exploration, is currently constructing a post-combustion capture system at NRG's WA Parish generating station near Houston, TX. The post-combustion capture system will utilize MHI amine-based solvents and is currently being constructed with plans to initiate operation in 2016.
Construction on Mississippi Power's Kemper County Energy Center IGCC facility is now nearly complete. The combined cycle portion of the facility has been generating power using natural gas. The gasification portion of the facility and the carbon capture system are undergoing system checks and training to enable commercial operations using a UOP Selexol
Another full-scale project, the Summit Power Texas Clean Energy Project has not commenced construction but remains a viable project. Several other full-scale projects have been proposed and have progressed through the early stages of design, but have been cancelled or postponed for a variety of reasons.
Some cost information is also available for small demonstration projects—including those that have been supported by USDOE research programs. These projects would include Alabama Power's demonstration project at Plant Barry and the AEP/Alstom demonstration at Plant Mountaineer.
Many commenters felt that the EPA should rely on those high costs when considering whether the costs are reasonable. The costs from these large-scale projects appear to be consistently higher than those projected by techno-economic models. However, the costs from these full-scale projects represent first-of-a-kind (FOAK) costs and, it is reasonable to expect these costs to come down to the level projected in the NETL and other techno-economic studies for the next new projects that are built—which are the sources that would be subject to this standard.
Significant reductions in the cost of CO
The NETL cost estimates reasonably account for this documented phenomenon. Specifically, “[I]n all cases, the report intends to represent the next commercial offering, and relies on vendor cost estimates for component technologies. It also applies process contingencies at the appropriate subsystem levels in an attempt to account for expected but undefined costs (a challenge for emerging technologies).”
Commenters argued that the next plants to be built would still reflect first-of-a-kind costs, pointing to the newness of the technology and the lack of operating experience,
The DOE/NETL sponsors an extensive research, development and demonstration program that is focused on developing advanced technology options that will dramatically lower the cost of capturing CO
The DOE/NETL and private industry are continuing to sponsor research on advanced solvents (including new classes of amines) to improve the CO
As noted in Section V.H.7.d above, SaskPower has created the CCS Global Consortium to facilitate further knowledge regarding, and use of, carbon capture technology.
We also note certain features of the commercial plants already built that suggest that their costs are uniquely high, and otherwise not fairly comparable to the costs of plants meeting the NSPS using the BSER. Most obviously, many of these projects involve deeper capture than the partial CCS that the EPA assumes in this final action. In addition, cost overruns at the Kemper facility, mentioned repeatedly in the public comments, resulted in major part from highly idiosyncratic circumstances, and are related to the cost of the IGCC system, not to the cost of CCS.
As the EPA noted, all indications suggest that very few new coal-fired power plants will be constructed in the foreseeable future. Although a small number of new coal-fired power plants have been built recently, the industry generally is not building these kinds of power plants at present and is not expected to do so for the foreseeable future. The reasons include the current economic environment and improved energy efficiency, which has led to lower electricity demand, and competitive current and projected natural gas prices. On average, the cost of generation from a new NGCC power plant is expected to be lower than the cost of generation from a new coal-fired power plant, and the EPA has concluded that, even in the absence of the requirements of this final rule, very few new coal-fired power plants will be built in the near term.
Some commenters, however, disagreed with this conclusion. They contended instead that it is the CCS-based NSPS that would preclude such new generation. However, as the EPA has discussed, there is considerable evidence that utilities and project developers are moving away—or have already moved away—from a long term dependence on coal-fired generating sources. A review of publicly available integrated resource plans show that many utilities are not considering construction of new coal-fired sources without CCS. See Section V. H.3 above. Few new coal-fired generating sources have commenced construction in the past 5 years and, of the projects that are currently in the development phase, the EPA is only aware of projects that will include CCS in the design. As we have noted in this preamble, the bulk of new
In addition, we note that the Administration's CCS Task Force report recognized that CCS would not become more widely available without the advent of a regulatory framework that promoted CCS or provided a strong price signal for CO
The EPA's estimates of costs take into account the transport of CO
Based on DOE/NETL studies, the EPA estimated that the total CO
The EPA believes its estimates of transportation and sequestration costs are reasonable. First, the EPA in fact includes cost estimates for CO
The EPA also carefully reviewed the assumptions on which the transport cost estimates are based and continues to find them reasonable. The NETL studies referenced in Section V.I.2 above based transport costs on a generic 100 km (62 mi) pipeline and a generic 80 kilometer pipeline.
With respect to sequestration, certain commenters argued that the EPA's cost analysis failed to account for many contingencies and uncertainties (surface and sub-surface property rights in particular), ignored the costs of GHGRP subpart RR, and also was not representative of the costs associated with specific GS site characterization, development, and operation/injection of monitoring wells. Commenter American Electric Power (AEP) referred to its own
The EPA's cost estimates account for the requirements of the Underground Injection Control Class VI program, and GHGRP subpart RR, among them site screening and evaluation costs, costs for injection wells and equipment, O&M costs, and monitoring costs. The estimated sequestration costs include operational and post-injection site care monitoring, which are components of the UIC Class VI requirements, and also reflect costs for sub-surface pore volume property rights acquisition.
The EPA's cost estimates for sequestration thus cover all aspects commenters claimed the EPA disregarded. The EPA believes that the use of costs and scenarios presented in the studies referenced are representative for purposes of the cost analysis. The NETL cost estimates upon which the EPA's costs draw directly from the UIC Class VI economic impact analysis.
With respect to AEP's experience with the Mountaineer demonstration project, sequestration siting issues are of course site-specific, and raise individual issues. For this reason, it is inappropriate to generalize from a particular individual experience. In this regard, as explained in Section V.N below, the construction permits issued by the EPA to-date under the Underground Injection Control Class VI regulations required far fewer wells for site characterization and monitoring than AEP found to be necessary at its Mountaineer site. Moreover, notwithstanding difficulties, the company was able to successfully drill and complete wells, and safely inject captured CO
The EPA finds the final standard of 1,400 lb CO
Importantly, compliance with the standard must be demonstrated over a 12-operating-month average. The total CO
The post-combustion capture systems that have been utilized have proven to be reliable. The Boundary Dam facility has been operating full CCS successfully at commercial scale since October 2014. As described earlier, in evaluating results from the Mountaineer slip-
The use of specific coal types can affect the amount of CO
Although the definition of “standard of performance” does not by its terms identify the amount of emissions from the category of sources and the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” the D.C. Circuit has stated that the EPA must do so. See
The final standard of performance will result in meaningful and significant emission reductions of GHG emissions from a new coal-fired steam generating unit. The EPA estimates that a new highly efficient 500 MW coal-fired SCPC meeting the final standard of 1,400 lb CO
For comparison, see Table 12 below which provides the amount of CO
Researchers at Carnegie Mellon University (CMU) have studied the history and the technological response to environmental regulations.
Much like carbon capture scrubbers today, the technology to capture and remove SO
Many of the early Flue Gas Desulfurization (FGD) units did not perform well, as the technology at that time was poorly understood and there was little or no prior experience on coal-fired power plants. In contrast, amine-based capture systems have a much longer history of reliable use at coal-fired plants and other industrial sources. There is also a better understanding of the amine process chemistry and overall process design—and project developers have much sophisticated analytical tools available today than in the 1970s during the development of FGD scrubber technologies.
While R&D efforts were essential to achieving improvements in FGD scrubber technology—and are also very important to improving carbon capture technologies, the influence of regulatory actions that establish commercial markets for advanced technologies cannot be minimized. The existence of national government regulation for SO
In the following sections of the preamble, we discuss issues associated with the disposition of captured CO
Geologic sequestration (
Storage security is expected to increase over time through post-closure, resulting in a decrease in potential risks.
The effectiveness of long-term trapping of CO
GS is feasible in different types of geologic formations including deep saline formations (formations with high salinity formation fluids) or in oil and gas formations, such as where injected CO
CO
As discussed below in Section M.7, a few states do not have geologic conditions suitable for GS, or may not be located in proximity to these areas. However, in some cases, demand in those states can be served by coal-fired power plants located in areas suitable for GS, and in other cases, coal-fired power plants are unlikely to be built in those areas for other reasons, such as the lack of available coal or state law prohibitions and restrictions against coal-fired power plants.
The DOE and the United States Geological Survey (USGS) have independently conducted preliminary analyses of the availability and potential CO
The DOE has created a network of seven Regional Carbon Sequestration Partnerships (RCSPs) to deploy large-scale field projects in different geologic settings across the country to demonstrate that GS can be achieved safely, permanently, and economically at large scales. Collectively, the seven RCSPs represent regions encompassing 97 percent of coal-fired CO
Eight RCSP “Development Phase” projects have been initiated and five of the eight projects are injecting or have completed CO
Although the determination that the BSER is adequately demonstrated and the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA also recognizes the potential for securely sequestering CO
EOR is a technique that is used to increase the production of oil. Approaches used for EOR include steam injection, injection of specific fluids such as surfactants and polymers, and gas injection including nitrogen and CO
The amount of CO
CO
EOR has been successfully used at numerous production fields throughout the United States to increase oil recovery. The oil industry in the United States has over 40 years of experience with EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the United States.
Currently, 12 states have active EOR operations and most have developed an extensive CO
A DOE-sponsored study has analyzed the geographic availability of applying EOR in 11 major oil producing regions of the United States and found that there is an opportunity to significantly increase the application of EOR to areas outside of current operations.
Some commenters raised concerns that data are extremely limited on the extent to which EOR operations permanently sequester CO
CO
The International Energy Agency Greenhouse Gas Programme conducted an extensive monitoring program at the Weyburn oil field in Saskatchewan between 2000 and 2010 (the site receiving CO
The Texas Bureau of Economic Geology also has been testing a wide range of surface and subsurface monitoring tools and approaches to document sequestration efficiency and sequestration permanence at the Cranfield oilfield in Mississippi (see Section L.1 above).
As discussed in Section M.1 above and as shown in Figure 1, the United States has widespread potential for storage, including in deep saline formations and oil and gas formations. However, some commenters maintained that the EPA's information regarding availability of GS sites is overly general and ignores important individual considerations. A number of commenters, for example, maintained that site conditions often make monitoring difficult or impossible, so
Project- and site-specific factors do influence where CO
Potential alternatives to sequestering CO
The Skyonics Skymine project, which opened its demonstration project in October 2014, is an example of captured CO
A few commenters suggested that CO
In the January 2014 proposal, the EPA noted that it would need to adopt a mechanism to evaluate these alternative technologies before any could be used in lieu of geologic sequestration. 79 FR at 1484. The EPA is establishing such a mechanism in this final rule. See § 60.5555(g). The rule provides for a case-by-case adjudication by the EPA of applications seeking to demonstrate to the EPA that a non-geologic sequestration technology would result in permanent confinement of captured CO
As noted at proposal, given the unlikelihood of new coal-fired EGUs being constructed, the EPA does not expect there to be many (if any) applications for use of non-geologic sequestration technology. 79 FR at 1484.
CO
Some commenters argued that the existing CO
The EPA does not agree. The CO
Examples are identified below.
Kinder Morgan has reported several proposed pipeline projects including the proposed expansion of the existing Cortez CO
Denbury reported that the company utilized approximately 70 million cubic feet per day of anthropogenic CO
Denbury completed the final section of the 325-mile Green Pipeline for transporting CO
A project being constructed by NRG and JX Nippon Oil & Gas Exploration (Petra Nova) would capture CO
Some commenters suggested that there may be challenges associated with the safety of transporting supercritical CO
The EPA has carefully evaluated the safety of pipelines used to transport captured CO
Several states have established emission performance standards or other measures to limit emissions of GHGs from new EGUs that are comparable to or more stringent than the final standard in this rulemaking. For example, in September 2006, California Governor Schwarzenegger signed into law Senate Bill 1368. The law limits long-term investments in base load generation by the state's utilities to power plants that meet an emissions performance standard jointly established by the California Energy Commission and the California Public Utilities Commission. The Energy Commission has designed regulations that establish a standard for new and existing base load generation owned by, or under long-term contract to publicly owned utilities, of 1,100 lb CO
In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which established statewide GHG emissions reduction goals, and imposed an emission standard that applies to any base load electric generation that commenced operation after June 1, 2008 and is located in Washington, whether or not that generation serves load located within the state. Base load generation facilities must initially comply with an emission limit of 1,100 lb CO
In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that facilities generating base load electricity, whether gas- or coal-fired, must have emissions equal to or less than 1,100 lb CO
In 2012 New York established emission standards of CO
In May 2007, Montana Governor Schweitzer signed House Bill 25, adopting a CO
On January 12, 2009, Illinois Governor Blagojevich signed Senate Bill 1987, the Clean Coal Portfolio Standard Law. The legislation establishes emission standards for new power plants that use coal as their primary feedstock. From 2009-2015, new coal-fueled power plants must capture and store 50 percent of the carbon emissions that the facility would otherwise emit; from 2016-2017, 70 percent must be captured and stored; and after 2017, 90 percent must be captured and stored.
In addition, as discussed in the proposal, electricity demand in states
For example, we noted in the proposal that there are many examples where coal-fired power generated in one state is used to supply electricity in other states. In the proposal we specifically noted that historically nearly 40 percent of the power for the City of Los Angeles was provided from two coal-fired power plants located in Arizona and Utah and Idaho Power, which serves customers in Idaho and Eastern Oregon, meets its demand in part from coal-fired power plants located in Wyoming and Nevada. 79 FR at 1478.
In the Technical Support Document on Geographic Availability (Geographic Availability TSD), we explore in greater detail the issue of coal-by-wire and the ability of demand in areas without geologic sequestration to be served by coal generation located in areas that have access to geologic sequestration. Figure 1 of this preamble (a color version of which is provided as Figure 1 of the Geographic Availability TSD) depicts areas of the country with: (1) existing CO
As an initial matter, we note that the data included in Figure 1 is a conservative outlook of potential areas available for the development of CO
As one considers the areas on the map depicted in Figure 1 that fall outside of the above enumerated categories, in many instances, we find areas with low population density, areas that are already served by transmission lines that could deliver coal-by-wire, and/or areas that have made policy or other decisions not to pursue a resource mix that includes coal. In many of these areas, utilities, electric cooperatives, and municipalities have a history of joint ownership of coal-fired generation outside the region or contracting with coal and other generation in outside areas to meet their demand. Some of the relevant areas are in RTOs
This section discusses the different regulatory components, already in place, that assure the safety and effectiveness of GS. This section, by demonstrating that GS is already covered by an effective regulatory structure, complements the analysis of the technical feasibility of GS contained in Sec. V.M. Together, these sections affirm that the technical feasibility of GS is adequately demonstrated.
In 2010, the EPA finalized an effective and coherent regulatory framework to ensure the long-term, secure and safe storage of large volumes of CO
In addition, to complement both the Class VI and Class II rules, the EPA used CAA authority to develop air-side monitoring and reporting requirements for CO
As explained below, these requirements help ensure that sequestered CO
Under SDWA, the EPA developed the UIC Program to regulate the underground injection of fluids in a manner that ensures protection of USDWs. UIC regulations establish six different well classes that manage a range of injectates (
The EPA's UIC regulations define the term USDWs to include current and future sources of drinking water and aquifers that contain a sufficient quantity of ground water to supply a public water system, where formation fluids either are currently being used for human consumption or that contain less than 10,000 ppm total dissolved solids.
In 2010, the EPA established a new class of well, Class VI. Class VI wells are used to inject CO
Site characterization includes assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of a proposed GS site to ensure that Class VI wells are sited in appropriate locations and CO
Owners or operators of Class VI wells must delineate the project area of review using computational modeling that accounts for the physical and chemical properties of the injected CO
Well construction must use materials that can withstand contact with CO
Requirements for operation of Class VI injection wells account for the unique conditions that will occur during large-scale GS including buoyancy, corrosivity, and high sustained pressures over long periods of operation.
Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate analysis, mechanical integrity testing, corrosion monitoring, ground water and geochemical monitoring, pressure fall-off testing, CO
Although subsurface monitoring is the primary and effective means of determining if there are any risks to a USDW, the Class VI rule also authorizes the UIC Program Director to require surface air and/or soil gas monitoring on a site-specific basis. For example, the Class VI Director may require surface air/soil gas monitoring of the flux of CO
Class VI well owners or operators must develop and update a site-specific, comprehensive emergency and remedial response plan that describes actions to be taken (
Financial responsibility demonstrations are required to ensure that funds will be available for all area of review corrective action, injection well plugging, post-injection site care, site closure, and emergency and remedial response.
Following cessation of injection, the operator must conduct comprehensive post-injection site care activities to show the position of the CO
The EPA has completed technical guidance documents on Class VI well site characterization, area of review and corrective action, well testing and monitoring, project plan development, well construction, and financial responsibility.
To inform the development of the UIC Class VI rule, the EPA solicited stakeholder input and reviewed ongoing domestic and international GS research, demonstration, and deployment projects. The EPA also leveraged injection experience of the UIC Program, such as injection via Class II wells for EOR. A description of the work conducted by the EPA in support of the UIC Class VI rule can be found in the preamble for the final rule (see 75 FR 77230 and 77237-240(December 10, 2010)).
The EPA has issued Class VI permits for six wells under two projects. In September 2014, a UIC Class VI injection well permit (to construct) was issued by the EPA to Archer Daniels Midland for an ethanol facility in Decatur, Illinois. The goal of the project is to demonstrate the ability of the Mount Simon geologic formation, a deep saline formation, to accept and retain industrial scale volumes of CO
Both permit applicants addressed siting and operational aspects of GS (including issues relating to volumes of the CO
The permitting of these projects illustrates that permit applicants were able to address perceived challenges to issuance of Class VI permits. These permits demonstrate that these projects are capable of safely and securely sequestering large volumes of CO
As explained in Section M.3 above, CO
UIC Class II regulations issued under section 1421 of SDWA provide minimum federal requirements for site characterization, area of review, well construction (
Section 1425 of SDWA allows states to demonstrate that their program is effective in preventing endangerment of USDWs. These programs must include permitting, inspection, monitoring, record-keeping, and reporting components.
The GHGRP requires reporting of facility-level GHG data and other relevant information from large sources and suppliers in the United States. The final rules under 40 CFR part 60 specifically require that if an affected EGU captures CO
Specifically, subpart PP provides requirements to account for CO
This rule finalizes amendments to subpart PP reporting requirements, specifically requiring that the following pieces of information be reported: (1) the electronic GHG Reporting Tool identification (e-GGRT ID) of the EGU facility from which CO
As noted, this final rule also requires that any affected EGU unit that captures CO
Reporting under subpart RR is required for all facilities that have received a Class VI UIC permit for injection of CO
A delineation of monitoring areas based on the CO
An identification and evaluation of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO
A strategy for detecting and quantifying any surface leakage of CO
An approach for establishing the expected baselines for monitoring CO
A summary of considerations made to calculate site-specific variables for the mass balance equation. Site-specific variables may include calculating CO
Subpart RR provides a nationally consistent mass balance framework for reporting the mass of CO
Under this final rule, any well receiving CO
Together the requirements of the UIC and GHGRP programs help ensure that sequestered CO
The UIC and GHGRP programs are built upon an understanding of the mechanisms by which CO
Structural and stratigraphic trapping is a physical trapping mechanism that occurs when the CO
Residual trapping is a physical trapping mechanism that occurs as residual CO
Adsorption trapping is another physical trapping mechanism that occurs when CO
Solubility trapping is a geochemical trapping mechanism where a portion of the CO
Mineral trapping is a geochemical trapping mechanism that occurs when chemical reactions between the dissolved CO
As just discussed in Section V.N.1, the UIC Class VI rule provides a framework to ensure the safety of underground injection of CO
Site characterization provides the foundation for successful GS projects. It includes evaluation of the chemical and physical mechanisms that will occur in the subsurface to immobilize and securely store the CO
The Class VI rules contain rigorous subsurface monitoring requirements to assure that the chosen site is functioning as characterized. This subsurface monitoring should detect leakage of CO
Likewise, UIC Class VI mechanical integrity testing requirements are designed to confirm that a well maintains internal and external mechanical integrity. Continuous monitoring of the internal mechanical integrity of Class VI wells ensures that injection wells maintain integrity and serves as a way to detect problems with the well system. Mechanical integrity testing provides an early indication of potential issues that could lead to CO
Further assurance is provided by the regulatory requirement that injection must cease if there is evidence that the injected CO
Following cessation of injection, the operator must conduct comprehensive post-injection site care to show the position of the CO
As the EPA has found, the UIC Class VI injection well requirements protect against releases from all exposure pathways. Specifically, the EPA stated that the Class VI rules “[are] specifically designed to ensure that the CO
GHGRP subpart RR complements these UIC Class VI requirements. Requirements under the UIC program are focused on demonstrating that USDWs are not endangered as a result of CO
In summary, there are well-recognized physical mechanisms for storing CO
The Class II rules likewise are designed to protect USDWs during EOR operation, including the injection of CO
CO
Commenters maintained that GS was not demonstrated for CO
The EPA does not agree. CO
GS of anthropogenic CO
Second, international experience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO
The Sleipner CO
Snøhvit is another large offshore CO
As discussed above in Sections V.E.2.a and M, CO
CO
At the In Salah CO
These projects demonstrate that sequestration of CO
One commenter maintained as a matter of law that a standard predicated on use of CCS is not a “system of emission reduction”, and therefore is not a “standard of performance” within the meaning of section 111 (a)(1) of the Act. The commenter argued that the standard does not require sequestration of captured CO
The EPA disagrees with both the legal and factual assertions in this comment. As to the legal point, the commenter fails to distinguish capture and sequestration of carbon from every other section 111 standard which is predicated on capture of a pollutant. Indeed, all emission standards not predicated on outright pollutant destruction involve capture of the pollutant and its subsequent disposition in the capturing medium. Thus, metals are captured in devices like baghouses or scrubbers, leaving a solid waste or wastewater to be managed. Gases can be captured with activated carbon or under pressure, again requiring further management of the captured pollutant(s). The EPA is required to consider these potential implications in promulgating an NSPS. See section 111(a)(1) (in promulgating a standard of performance under section 111, the EPA must “tak[e] into account . . . any nonair quality health and environmental
The further comment that the standard is arbitrary because it fails to impose any requirements on the captured CO
In this regard, the EPA notes that at proposal it acknowledged the possibility “that there can be downstream losses of CO
The EPA addresses this comment in more detail in Chapter 2 of the Response-to-Comment Document.
A number of commenters maintained that the Class VI rules could effectively force all Class II wells to transition to Class VI wells if they inject anthropogenic CO
Geologic storage of CO
Use of anthropogenic CO
Class VI site closure requirements are not required for Class II CO
EOR operations that are focused on oil or gas production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Class II permitted EOR operation, the key factor in determining the potential need to transition an EOR operation from Class II to Class VI is increased risk to USDWs related to significant storage of CO
A number of commenters maintained that no EOR operator would accept captured carbon from an EGU due to the reporting and other regulatory burdens imposed by the monitoring requirements of GHGRP subpart RR.
The EPA disagrees with this comment in several respects. First, the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, not on EOR. However, the EPA also recognizes the potential for sequestering CO
The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR are relatively modest, especially in comparison with revenues from an EOR field. In the economic impact analysis for subpart RR, the EPA estimated that an EOR project with a Class II permit would incur a first year cost of up to $147,030 to develop an MRV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per year.
Furthermore, there is a demand for new CO
The EPA addresses these comments in more detail in the Response to Comment Document.
Certain commenters voiced concerns that regulatory requirements for hazardous wastes might apply to captured CO
Other commenters claimed that various legal uncertainties preclude a finding that geologic sequestration of CO
An IPCC special report on CCS found that with an appropriate site selection, a monitoring program, a regulatory system, and the appropriate use of remediation methods, the risks of GS would be comparable to risks of current activities, such as EOR, acid gas injection and underground natural gas storage.
Commenter American Electric Power (AEP) referred to its own experience with the Mountaineer demonstration project. AEP noted that although this project was not full scale, finding a suitable repository, notwithstanding a generally favorable geologic area, proved difficult. The company referred to years spent in site characterization and digging multiple wells.
The EPA agrees that robust site characterization and selection is important to ensuring capacity needs are met and that the sequestered CO
In the time since the commenter submitted comments several Class VI permits have been issued by the EPA. These projects demonstrate that a GS site permit applicant could potentially prepare and obtain a UIC permit concurrent with permits required for an EGU. With respect to AEP's experience with the Mountaineer demonstration project, notwithstanding difficulties, the company was able to successfully dig wells, and safely inject captured CO
As part of the determination that SCPC with partial CCS is the best system of emission reduction adequately demonstrated, the EPA has given careful consideration to non-air quality health and environmental impacts and energy requirements, as required by CAA section 111 (a). We have also considered those factors for alternative potential compliance paths to assure that the standard does not have unintended adverse health, environmental or energy-related consequences. The EPA finds that neither the BSER, nor the possible alternative compliance pathways, would have adverse consequences from either a non-air quality impact or energy requirement perspective.
1. Transport and Sequestration of Captured CO
As just discussed in detail, the EPA finds that the Class VI and II rules, as complemented by the subpart RR GHGRP reporting and monitoring requirements, amply safeguard against potential of injected CO
Commenters claimed that the EPA ignored the negative environmental impacts of the use of CCS for the mitigation of CO
The EPA examined water use predicted from the updated DOE/NETL studies in order to determine the magnitude of increased water usage for a new SCPC implementing partial CCS to meet the final standard of 1,400 lb CO
Similar to other air pollution controls—such as a wet flue gas desulfurization scrubber—utilization of post-combustion amine-based capture systems results in increased consumption of water. However, by finalizing a standard that is less stringent than the proposed limitation and by rejecting full CCS as the BSER, the EPA has reduced the increased amount of water needed as compared to a similar unit without CCS. Further, the EPA notes that there are additional opportunities to minimize the water usage at such a facility.
The EPA also examined the predicted water usage for a new IGCC and for a new IGCC implementing 90 percent CCS. The predicted water consumption for the new IGCC unit is nearly 20 percent less than that predicted for the new SCPC unit without CCS (and almost 25 percent less than the SCPC unit meeting the final standard). The EPA rejected new IGCC implementing full CCS as BSER because the predicted costs were significantly more than alternative technologies. The EPA also does not find that a new IGCC EGU is part of the final BSER (for reasons discussed in Section V.P). However, the EPA does note that IGCC is a viable alternative compliance option and, as shown here, would result in less water consumption than a compliant SCPC EGU. The EPA also notes that predicted water consumption at a new NGCC unit would be less than half that for a new SCPC EGU with the same net output.
The EPA also examined the expected impacts on energy requirements for a new unit meeting the final promulgated standard and finds impacts to be minimal. Specifically, the EPA examined the increased auxiliary load or parasitic energy requirements of a system implementing CCS. The EPA examined the predicted auxiliary power demand from the updated DOE/NETL studies in order to determine the increased energy requirement for a new SCPC implementing partial CCS to meet the final standard of 1,400 lb CO
The auxiliary power demand is the amount of the gross power output that is utilized within the facility rather than used to produce electricity for sale to the grid. The parasitic power demand (or parasitic load) is the percentage of the gross power output that is needed to meet the auxiliary power demand.
The results in Table 14 show that a new SCPC unit without CCS can expect a parasitic power demand of about 5.2 percent. A new SCPC unit meeting the
The EPA also notes that there is on-going research sponsored by DOE/NETL and others to further reduce the energy requirements of the carbon capture systems. Progress is being made. As was mentioned previously, the heat duty (the energy required to regenerate the capture solvent) for the amine scrubbing process used at the Searles Valley facility in the mid-70's was about 12 MJ/mt CO
The EPA also examined the predicted parasitic power demand for a new IGCC and for a new IGCC implementing 90 percent CCS. As we have noted elsewhere, the auxiliary power demand for a new IGCC unit is more than that for that of a new SCPC. As one can see in Table 14, a new IGCC unit can expect to see a nearly 17 percent parasitic power demand; and a new IGCC unit implementing full CCS would expect a parasitic power demand of nearly 30 percent. Of course, the EPA rejected new IGCC implementing full CCS as BSER because of the potentially unreasonable costs. The EPA also does not find that a new IGCC EGU is part of the final BSER (for reasons discussed elsewhere in Section V.P.1 below). However, as we have noted, the EPA does find IGCC to be a viable alternative compliance option. Utilities and project developers should consider the increased auxiliary power demand for an IGCC when considering their options for new power generation. The EPA also notes that the predicted parasitic load for a new NGCC unit would be about 2 percent—less than half that for a new SCPC EGU with the same net output.
With respect to potential nationwide impacts on energy requirements, as described above in Section V.H.3 and more extensively in the RIA chapter 4, the EPA reasonably projects that no new non-compliant fossil-fuel fired steam electric capacity will be constructed through 2022 (the end of the 8 year review cycle for NSPS). It is possible, as described earlier, that some new sources could be built to preserve fuel diversity, but even so, the number of such sources would be small and therefore would not significantly impact national energy requirements (assuming that such sources would not already be reflected in the baseline conditions just noted).
In light of the comments received, the EPA re-examined several alternative systems of emission reduction and reaffirms in this rulemaking our proposed determination that those alternatives do not represent the “best” system of emission reduction when compared against the other available emission reduction options. These are described below. See also Section IV.B.1 above.
In the January 2014 proposal, we considered whether `Highly Efficient New Generation without CCS Technology' should constitute the BSER for new steam generating units. 79 FR at 1468-69. The discussion focused on the performance of highly efficient generation technology (that does not include any implementation of CCS), such as a supercritical
All these options are technically feasible—there are numerous examples of each operating in the U.S. and worldwide. However, we do not find them to qualify as the best system for reduction of CO
At the outset, we reviewed the emission rates of efficient PC and CFB units. According to the DOE/NETL estimates, a newly constructed subcritical PC unit firing bituminous coal would emit approximately 1,800 lb CO
Some commenters noted that new coal-fired plants utilizing supercritical boiler design or IGCC would provide substantial emission reductions compared to the emissions from the existing subcritical coal plants that are currently in wide use in the power sector. However, most of the recent new power sector projects using solid fossil fuel (coal or petroleum coke) as the primary fuel—both those that have been constructed and those that have been proposed—are supercritical boilers and IGCC units. About 60 percent of new coal-fired utility boiler capacity that has come on-line since 2005 was supercritical and of the new capacity that came on-line since 2010, about 70 percent was supercritical. No new coal-fired utility boilers began operation in either 2013 or 2014. Coal-fired power plants that have come on-line most recently include AEP's John W. Turk, Jr. Power Plant, which is a 600 MW ultra-supercritical
The EPA is aware of only one new coal-fired power plant that is actively in the construction phase. That plant is Mississippi Power's Kemper County Energy Facility in Kemper County, MS—an IGCC unit that plans to begin operations in 2016 and will implement partial CCS to capture approximately 65 percent of the available CO
Considering the direction that the power sector has been taking and the changes that it is undergoing, identifying a new supercritical unit as the BSER and requiring an emission limitation based on the performance of such units thus would provide few, if any, additional CO
The EPA also considered IGCC technology and whether it represents the BSER for new power plants utilizing coal or other solid fossil fuels. IGCC units, on a gross-output basis, have inherently lower CO
As is shown in Section V.J and H, additional emission reductions beyond those that would result from an emission standard based on a new SCPC boiler or even a new IGCC unit as the BSER can be achieved at a reasonable cost. Because practicable emission controls are available that are of reasonable cost at the source level and that will have little cost and energy impact at the national level, the EPA is according significant weight to the factor of amount of emissions reductions in determining the BSER. As discussed above, the D.C. Circuit has emphasized this factor in describing the purpose of CAA section 111 as to achieve “as much [emission reduction] as practicable.”
As discussed above, the EPA is justifying its identification of the BSER based on its weighing of the factors explicitly identified in CAA section 111(a)(1), including the amount of the emission reduction. Under the D.C. Circuit case law, encouraging the development and implementation of advanced control technology must also be considered (and, in any case, may reasonably be considered; see Section V.H.3.d above). Consideration of this factor confirms the EPA's decision not to identify highly efficient generation technology (without CCS) as the BSER. At present, CCS technologies are the most promising options to achieve significant reductions in CO
The Intergovernmental Panel on Climate Change (IPCC) recently released its Fifth Assessment report,
American Electric Power (AEP), in an evaluation of lessons learned from the Phase 1 of its Mountaineer CCS project, wrote: “AEP still believes the advancement of CCS is critical for the sustainability of coal-fired generation.”
Some commenters felt that the proposed standard of performance for new steam generating units, based on implementation of partial CCS at an emission rate of 1,100 lb/MWh-g, would not serve to promote the increased deployment and implementation of CCS. The commenters argued that such a standard could instead have the unintended result of discouraging the further development of advanced coal generating technologies such as ultra-supercritical boilers and improved IGCC designs.
Commenters further argued that such a standard will stifle further
The EPA does not agree with these arguments and, in particular, does not see how a standard that is not predicated on performance of an advanced control technology would serve to promote development and deployment of that advanced control technology. On the contrary, the history of regulatory actions has shown that emission standards that are based on performance of advanced control equipment lead to increased use of that control equipment, and that the absence of a requirement stifles technology development.
There is a dramatic instance of this paradigm presented in the present record. In 2011, AEP deferred construction of a large-scale CCS retrofit demonstration project on one of its coal-fired power plants because the state's utility regulators would not approve cost recovery for CCS investments without a regulatory requirement to reduce CO
We are placing the project on hold until economic and policy conditions create a viable path forward . . . We are clearly in a classic `which comes first?' situation. The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effective generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry's share.
Some commenters also argued that the incremental cost associated with including CCS at the proposed level would prevent new coal-fired units from being built. Instead, they advocated for a standard based on most efficient technology (supercritical) coupled with government subsidies to advance and promote CCS technology. The final standard is less stringent than that proposed, and can be met at a lower cost than the proposed standard, and as explained above in Section V.H, the EPA has carefully evaluated those costs and finds them to be reasonable. Further, the record and current economic conditions (fuel costs, renewables, demand growth, etc.) show that non-economic factors such as a desire for fuel diversity will likely drive future development of any new coal-fired EGUs. For this reason, the EPA does not find the commenters' bare assertions that the incremental cost of CCS (particularly as reasonably modulated for this final standard) would make the difference between constructing and not constructing new coal capacity to be persuasive. Rather, a cost-reasonable standard reflecting use of the new technology is what will drive new technology deployment.
The EPA expects that it is unlikely that a new IGCC unit would install partial CCS to meet the final standard unless the facility is built to take advantage of EOR opportunities or to operate as a poly-generation facility (
We also reconsidered whether the emission limitation for new coal-fired EGUs should be based on the performance of full implementation of CCS technology. For a newly constructed utility boiler, this would mean that a post-combustion capture system would be used to treat the entire flue gas stream to achieve an approximately 90 percent reduction in CO
In the proposal for newly constructed sources, we found that “full CCS” would certainly result in significant CO
The EPA finds that the best system of emission reduction adequately demonstrated is a highly efficient supercritical pulverized coal boiler using post-combustion partial CCS so that CO
The EPA has determined that, as proposed, the BSER for steam generating units that trigger the modification provisions is each affected unit's own best potential performance as determined by that unit's historical performance. The final standards of performance are similar to those proposed in the June 2014 proposal. Differences between the proposed standards and the final standards issued in this action reflect responses to comments received on the proposal. Those changes are described below.
As noted previously, the EPA is issuing final emission standards only for affected modified steam generating units that conduct modifications resulting in a hourly increase in CO
Final applicability criteria for modified steam generating EGUs include those discussed earlier in Section III.A.1 (General Applicability) and Section III.A.3 (Applicability Specific to Modified Sources).
CAA section 111(a)(4) defines a “modification” as “any physical change in, or change in the method of operation of, a stationary source” that either “increases the amount of any air pollutant emitted by such source or . . . results in the emission of any air pollutant not previously emitted.” Certain types of physical or operational changes are exempt from consideration as a modification. Those are described in 40 CFR 60.2, 60.14(e). To be clear, our action in this final rule, and the discussion below, does not change anything concerning what constitutes or does not constitute a modification under the CAA or the EPA's regulations.
A modified steam generating unit is a source that fits the definition and applicability criteria of a fossil fuel-fired steam generating unit and that commences a qualifying modification on or after June 18, 2014 (the publication date of the proposed modification standards). 79 FR 34960.
For the reasons discussed below, the EPA in this final action is finalizing requirements only for steam generating units that conduct modifications resulting in an increase in hourly CO
The effect of the EPA's deferral on setting standards for sources undertaking modifications resulting in smaller increases in CO
As we discussed in the June 2014 proposal, the EPA has historically been notified of only a limited number of NSPS modifications
In establishing standards of performance at this time for modifications with large emissions increases, but not for those with small increases, the EPA is exercising its policy discretion to promulgate regulatory requirements in a sequential fashion for classes of modifications within a source category, accounting for the information available to the agency, while also focusing initially on those modifications with the greatest potential environmental impact. This approach is consistent with the case law that authorizes agencies to establish a regulatory framework in an incremental fashion, that is, a step at a time.
To be clear, the EPA is not reaching a final decision as to whether it will regulate modifications with smaller increases, or even that such modifications should be subject to different requirements than we are finalizing in this rule for the modifications with larger increases. We have made no decisions and this matter is not concluded. We plan to continue to gather information, consider the options for modifications with smaller increases, and, in the future, develop a proposal for these modifications or otherwise take appropriate steps.
As a means of determining the proper threshold between the larger and smaller increases in CO
An example of such major upgrade would be work performed at AmerenUE's Labadie Plant, a facility with four 600-MW (nominal) coal-fired units located 35 miles west of St. Louis. In the early 2000s, plant staff conducted process improvements that raised maximum unit capacity by nearly 10 percent (from 580 MW to 630 MW).
Another example is the refurbishment of the 2,100 MW Eskom Arnot coal-fired power plant in South Africa with a resulting increase in its power output by 300 MW to 2,400 MW—an increase in capacity of 14 percent.
The EPA does not intend to imply that these specific projects would have resulted in an increase in hourly CO
The EPA believes that it is reasonable to set the threshold between “large” modifications and “small” modifications at 10 percent, a level commensurate with the magnitude of the emissions increases that could result from the types of projects described above, and we are issuing a final standard of performance for those sources that conduct modifications resulting in hourly CO
Therefore, the EPA is withdrawing the proposed standards for those sources that conduct modifications resulting in a hourly increase in CO
The EPA notes that some commenters expressed concern that a number of existing fossil steam generating units, in order to fulfill requirements of an approved CAA section 111(d) plan, may pursue actions that involve physical or operational changes that result in some increase in their CO
The EPA does not have sufficient information at this time to predict the full array of actions that existing steam generating units may undertake in response to applicable requirements under an approved CAA section 111(d) plan, or which, if any, of these actions may result in increases in CO
The EPA has determined that, as was proposed, the BSER for steam generating units that trigger the modification provisions is the affected EGU's own best potential performance as determined by that source's historical performance.
The EPA proposed that the BSER for modified steam generating EGUs is each unit's own best potential performance based on a combination of best operating practices and equipment upgrades. Specifically, the EPA co-proposed two alternative standards for modified utility steam generating units. In the first co-proposed alternative, modified steam generating EGUs would be subject to a single emission standard determined by the affected EGU's best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction. The EPA proposed that the standard could be met through a combination of best operating practices and equipment upgrades. To account for facilities that have already implemented best practices and equipment upgrades, the proposal also specified that modified facilities would not have to meet an emission standard more stringent than the corresponding standard for reconstructed EGUs.
The EPA also co-proposed that the specific standard for modified sources would be dependent on the timing of the modification. We proposed that sources that modify prior to becoming subject to a CAA section 111(d) plan would be required to meet the same standard described in the first co-proposal—that is, the modified source would be required to meet a unit-specific emission limit determined by the affected EGU's best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction (based on equipment upgrades). We also proposed that sources that modify after becoming subject to a CAA section 111(d) plan would be required to meet a unit-specific emission limit that would be determined by the CAA section 111(d) implementing authority and would be based on the source's expected performance after implementation of identified unit-specific energy efficiency improvement opportunities.
The final standards in this action do not depend upon when the modification commences (as long as it commences after June 8, 2014). The EPA received comments on the June 2014 proposal that called into question the need to differentiate the standard based on when the modification was undertaken. Further, commenters noted that the proposed requirements for sources modifying after becoming subject to a CAA section 111(d) plan, which were based on energy efficiency improvement opportunities were vague and that standard setting under CAA section 111(b) is a federal duty and would require notice-and-comment rulemaking. The EPA considered those comments and has determined that we agree that there is no need for subcategories based on the timing of the modification.
The EPA based technical feasibility of the unit-specific efficiency improvement on analyses done to support heat rate improvement for the proposed CAA section 111(d) emission guidelines (Clean Power Plan). That work was summarized in Chapter 2 of the TSD, “GHG Abatement Measures”.
Any efficiency improvement made by EGUs for the purpose of reducing CO
We recognize that our cost analysis just described will represent the costs for some EGUs better than others because of differences in EGUs' individual circumstances. We further recognize that reduced generation from coal-fired EGUs will tend to reduce the fuel savings associated with heat rate improvements, thereby raising the effective cost of achieving the CO
This approach would achieve reasonable reductions in CO
As noted previously, the case law makes clear that the EPA is to consider
The applicability rationale for reconstructed utility steam generating units is the same as for newly constructed utility steam generating units. We are finalizing the same general criteria and not amending the reconstruction provisions included in the general provisions.
In the proposal, the EPA evaluated seven different control technology configurations to determine the BSER for reconstructed fossil fuel-fired boiler and IGCC EGUs: (1) The use of partial CCS, (2) conversion to (or co-firing with) natural gas, (3) the use of CHP, (4) hybrid power plants, (5) reductions in generation associated with dispatch changes, renewable generation, and demand side energy efficiency, (6) efficiency improvements achieved through the use of the most efficient generation technology, and (7) efficiency improvements achieved through a combination of best operating practices and equipment upgrades.
Although the EPA concluded that the first 4 technologies met most of the evaluation criteria, namely they are adequately demonstrated, have reasonable costs and provide GHG emissions reductions, they were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. We rejected best operating practices and equipment upgrades because we concluded the GHG reductions are not sufficient to qualify as BSER. The majority of commenters agree with the EPA's decision that these technologies are not BSER. In contrast, as described in more detail later in this section a few commenters did support partial CCS as BSER.
The fifth option, reductions in generation associated with dispatch changes, renewable generation, and demand side energy efficiency, is comparable to application of measures identified in building blocks two, three and four in the emissions guidelines that we proposed under CAA section 111(d). We solicited comment on any additional considerations that the EPA should take into account in the applicability of building blocks two, three and four in the BSER determination. Most commenters stated that building blocks two, three and four should not be considered for reconstructed sources.
The proposed BSER was based on the performance of the most efficient generation technology available, which we concluded was the use of the best available subcritical steam conditions for small units and the use of supercritical steam conditions for large units. We concluded this technology to be technically feasible, to have sufficient emission reductions, to have reasonable costs, and some opportunity for technological innovation. The proposed emission standard for these sources was 1,900 lb CO
We solicited comment on multiple aspects of the proposed standards. First, we solicited comment on a range of 1,600 to 2,000 lb CO
Many commenters supported the upper limits of the suggested ranges, saying the standard will be consistently met. Some commenters raised concerns about the achievability of these limits for the many boiler and fuel types. A few commenters suggested that there should be separate subcategories for coal-fired utility boilers and IGCC units, since IGCC units have demonstrated limits closer to 1,500 lb CO
Based on a review of the comments, we have concluded that both the proposed BSER and emission standards are appropriate, and we are finalizing the standards as proposed. Nothing in the comments changed our view that the BSER for reconstructed steam generating units should be based on the performance of a well operated and maintained EGU using the most efficient generation technology available, which we have concluded is a supercritical pulverized coal (SCPC) or supercritical circulating fluidized bed (CFB) boiler for large units, and subcritical for small units. As described at proposal, we have concluded that these standards are achievable by all the primary coal types. The final standards for reconstructed utility boilers and IGCC units is 1,800 lb CO
While the final emission standards are based on the identified BSER, a reconstructed EGU would not necessarily have to rebuild the boiler to use steam temperatures and pressures that are higher than the original design. As commenters noted, a reconstructed unit is not required to meet the standards if doing so is deemed to be “technologically and economically” infeasible. 40 CFR 60.15(b). This provision inherently requires case-by-case reconstruction determinations in the light of considerations of economic and technological feasibility. However, this case-by-case determination would consider the identified BSER (the use of the best available steam conditions), as well as—at a minimum—the first four technologies the EPA considered, but rejected, as BSER for a nationwide rule. One or more of these technologies could be technically feasible and reasonable cost, depending on site specific considerations and, if so, would likely result in sufficient GHG reductions to comply with the applicable reconstructed standards. Finally, in some cases, equipment upgrades and best operating practices would result in sufficient reductions to achieve the reconstructed standards.
This section summarizes the final applicability requirements, BSER determinations, and emission standards for newly constructed and reconstructed stationary combustion turbines. In addition, it also summarizes significant differences between the proposed and final provisions.
We are finalizing BSER determinations and emission standards for newly constructed and reconstructed stationary combustion turbines that (1) have a base load rating for fossil fuels greater than 260 GJ/h (250 MMBtu/h) and (2) serve a generator capable of selling more than 25 MW-net of electricity to the grid. We also are finalizing applicability requirements that will exempt from the final standards (1) all stationary combustion turbines that are dedicated non-fossil fuel-fired units (
For combustion turbines subject to an emission standard, we are finalizing three subcategories: base load natural gas-fired units, non-base load natural gas-fired units, and multi-fuel-fired units. We use the term base load natural gas-fired units to refer to stationary combustion turbines that (1) burn over 90 percent natural gas and (2) sell electricity in excess of their design efficiency (not to exceed 50 percent) multiplied by their potential electric output. To be in this subcategory, a stationary combustion turbine must exceed the “natural gas-use criterion” on a 12-operating-month rolling average and the “percentage electric sales” criterion on both a 12-operating-month and 3-year rolling average basis. We use the term non-base load natural gas-fired units to refer to stationary combustion turbines that (1) burn over 90 percent natural gas and (2) have net-electric sales equal to or below their design efficiency (not to exceed 50 percent) multiplied by their potential electric output. These criteria are calculated on the same rolling average bases as for the base load subcategory. Finally, we use the term multi-fuel-fired units to refer to stationary combustion turbines that burn 10 percent or more non-natural gas on a 12-operating-month rolling average basis. We are not finalizing the proposed emission standards for modified sources and are withdrawing those standards. We explain our rationale for these final decisions in Sections IX and XV of this preamble.
We are finalizing BSER determinations for the three subcategories of stationary combustion turbines referred to above: base load natural gas-fired units, non-base load natural gas-fired units, and multi-fuel-fired units. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the BSER is the use of efficient NGCC technology. For newly constructed and reconstructed non-base load natural gas-fired stationary combustion turbines, the BSER is the use of clean fuels (
For all newly constructed and reconstructed base load natural gas-fired combustion turbines, we are finalizing an emission standard of 1,000 lb CO
As shown
The final rule also includes exceptions to the broad applicability approach that we solicited comment on, with some changes that are responsive to public comments. Categorical exceptions to the broad applicability criteria are the exclusions for CHP units, non-fossil fuel units, and combustion turbines not able to combust natural gas. First, the proposed applicability criteria did not include CHP units that were constructed for the purpose of or that actually sell one-third or less of their potential electric output or 219,000 MWh, whichever is greater, to the grid. The final rule eliminates the “constructed for the purpose of” and actual sales aspects of the proposal and replaces them with an exemption for CHP units that take federally enforceable permit conditions restricting net-electric sales to a percentage of potential electric sales based on the unit's design efficiency or 219,000 MWh, whichever is greater. Second, the proposed applicability criteria did not include non-fossil fuel units that burn 10 percent or less fossil fuel on a 3-year rolling average. The final rule similarly replaces the actual fuel-use aspect of the proposal with an exemption for non-fossil fuel units that take federally enforceable permit conditions limiting fossil-fuel use to 10 percent or less of annual heat input capacity. Finally, the proposed applicability criteria did not include combustion turbines that burn 90 percent or less natural gas on a 3-year rolling average basis. In contrast, the final rule includes most fossil fuel-fired combustion turbines regardless of the amount of natural gas burned, with an exception for combustion turbines that are not connected to natural gas pipelines. Finally, in response to public comments, we are not finalizing the subcategories for large and small combustion turbines that were contained in the proposal. Instead, all base load natural gas-fired combustion turbines must meet an emission standard of 1,000 lb CO
This section
This section describes the proposed applicability criteria, applicability issues we specifically solicited comment on, the relevant significant comments, and the final applicability criteria. We also provide our rationale for finalizing applicability criteria based strictly on design and permit restrictions rather than actual operating characteristics. Finally, we explain why the proposed percentage electric sales and natural gas-use applicability criteria are being finalized instead as criteria to distinguish between separate subcategories of stationary combustion turbines.
In the January 2014 proposal, we proposed several applicability criteria for stationary combustion turbines. Specifically, to be subject to the proposed emission standards, we proposed that a unit must (1) be capable of combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel; (2) be constructed for the purpose of supplying and actually supply more than one-third of its potential electric output capacity to a utility power distribution system for sale (that is, to the grid) on a 3-year rolling average; (3) be constructed for the purpose of supplying and actually supply more than 219,000 MWh net-electric output to the grid on a 3-year rolling average; (4) combust over 10 percent fossil fuel on a 3-year rolling average; and (5) combust over 90 percent natural gas on a 3-year rolling average. We proposed exempting municipal solid waste combustors and commercial and industrial solid waste incinerators.
Under these proposed applicability criteria, two types of stationary combustion turbines that are currently subject to criteria pollutant standards under subpart KKKK would not have been subject to CO
We proposed the electric sales criteria in part because they already exist in other regulatory contexts (
While the proposed applicability criteria did not explicitly exempt simple cycle combustion turbines from the emission standards, we concluded that, as a practical matter, the vast majority of simple cycle turbines would be excluded because they historically have operated as peaking units and, on average, have sold less than five percent of their potential electric output on an annual basis, well below the proposed one-third electric sales threshold.
We solicited comment on a range of issues related to applicability. In conjunction with the proposed one-third (
We also solicited comment on whether the percentage electric sales criterion for stationary combustion turbines should be defined on a single calendar year basis. In addition, we solicited comment on eliminating the 219,000 MWh aspect of the total electric sales criterion to eliminate any incentive for generators to install multiple, small, less-efficient stationary combustion turbines that would be exempt due to their lower output. We further solicited comment on whether to provide an explicit exemption for all simple cycle combustion turbines regardless of the amount of electricity sold. We additionally solicited comment on how to implement the proposed electric sales, fossil fuel-use, and natural
We also solicited comment on excluding electricity sold during system emergencies from the calculation of percentage electric sales. The rationale for this exclusion was that simple cycle combustion turbines intended only for peaking applications might be required to operate above the proposed percentage electric sales threshold if a major power plant or transmission line became unexpectedly unavailable for an extended period of time. The EPA proposed that this flexibility would be appropriate if the unit were called upon to run after all other available generating assets were already running at full load.
In both the January 2014 proposal for newly constructed EGUs and the June 2014 proposal for modified and reconstructed EGUs, the EPA solicited comment on finalizing a broad applicability approach instead of the proposed approach. Under the proposed approach, a stationary combustion turbine could be an affected EGU one year, but not the next, depending on the unit's actual electric sales and the composition of fuel burned. The broad applicability approach is consistent with historical NSPS applicability approaches that are based on design criteria and include different emission standards for subcategories that are distinguished by operating characteristics. Specifically, we solicited comment on whether we should completely remove the electric sales and natural gas-use criteria from the general applicability framework. Instead, the percentage electric sales and natural gas-use thresholds would serve as subcategorization criteria for distinguishing among classes of EGUs and subcategory-specific emissions standards. Under this broad applicability approach, the “constructed for the purpose of” component of the percentage electric sales criterion would be completely eliminated so that applicability for combustion turbines would be determined only by a unit's base load rating (
This section summarizes the comments we received specific to each of the proposed applicability criteria. We also received more general comments on the scope of the proposed framework as compared to the scope of the broad applicability approach. Comments on applicability for dedicated non-fossil and CHP units are discussed in Section III.
Many commenters supported a base load rating of 260 GJ/h (250 MMBtu/h) because it is generally consistent with the threshold used in states participating in the Regional Greenhouse Gas Initiative (RGGI) and under Title IV programs. Other commenters opposed the proposed applicability thresholds and stated that all new, modified, and reconstructed units that sell electricity to the grid, including small EGUs and simple cycle combustion turbines, should be affected EGUs because they would otherwise have a competitive advantage in energy markets as they would not be required to internalize the costs of compliance.
Commenters noted that the 219,000 MWh total electric sales threshold put larger combustion turbines at a competitive disadvantage by distorting the market and could have the perverse impact of increasing CO
Commenters from the power sector generally supported a complete exemption for simple cycle turbines. These commenters stated that simple cycle turbines are uniquely capable of achieving the ramp rates (the rate at which a power plant can increase or decrease output) necessary to respond to emergency conditions and hourly variations in output from intermittent renewables. Commenters noted that simple cycle combustion turbines serve a different purpose than NGCC power blocks. In addition, commenters noted that electricity generation dispatch is based on the incremental cost to generate electricity and that because NGCC units have a lower incremental generation cost than simple cycle units, economics will drive the use of NGCC technologies over simple cycle units. However, commenters also stated that historic simple cycle operating data may not be representative of future system requirements as coal units retire, generation from intermittent renewable generation increases, and numerous market and regulatory drivers impact plant operations. In the absence of a complete exemption, these commenters supported a percentage electric sales threshold between 40 to 60 percent of a unit's potential electric output.
Some commenters said that because the proposed percentage electric sales criterion applied over a three-year period, it would adversely affect grid reliability because operators conservatively would hedge short-term operating decisions to ensure that they have sufficient capacity to respond to unexpected scenarios during future compliance periods when the demand for electricity is higher. These commenters were concerned that such compliance decisions would drive up the cost of electricity as the most efficient new units are taken out of service to avoid triggering the NSPS and older, less efficient units with no capacity factor limitations are ramped up instead.
Some commenters supported the sliding-scale approach (
In contrast, others commented that fast-start NGCC units intended for peaking and intermediate load applications can achieve comparable ramp rates to simple cycle combustion turbines, but with lower CO
Commenters noted that a complete exclusion for simple cycle turbines would create a regulatory incentive for generators to install and operate less efficient unaffected units instead of more efficient affected units, thereby increasing CO
Commenters in general supported the use of 3-year rolling averages instead of a single-year average for the percentage and total electric sales criteria because, in their view, the 3-year rolling averages would provide a better overall picture of normal operations. Some commenters stated that a rolling 12-month or calendar-year average could be severely skewed in a given year because of unforeseen or unpredicted events. They said that using a 3-year averaging methodology would provide system operators with needed flexibility to dispatch simple cycle units at higher than normal capacity factors. In contrast, some commenters stated that, because capacity is forward-looking (
Commenters noted that potential compliance issues could result from the inconsistent time frame between the 3-calendar-year applicability period and the 12-operating-month compliance period. For example, a facility could sell more than one-third of its potential electric output over a 3-year period, but sell less than one-third of its potential electric output during any given 12-operating-month compliance period within that 3-year period. During a 12-operating-month period with electric sales of less than one-third of potential electric output, a unit could be operating for long periods at part load and have multiple starts and stops. These operating conditions have the potential to increase CO
Regarding the relationship between the percentage electric sales criterion and system emergencies, multiple commenters supported exclusion of electricity generated as a result of a system emergency from counting towards net sales. These commenters stated that the exclusion was appropriate because the benefits of operating these units to generate electrical power during emergency conditions would outweigh any adverse impacts from short-term increases in CO
Multiple commenters opposed the exclusion of system emergencies when calculating a source's percentage electric sales for applicability purposes because NSPS must apply continuously, even during system emergencies. These commenters stated that the EPA does not have the authority under the CAA to suspend the applicability of a standard during periods of system emergency. Some commenters stated that an exclusion would be unnecessary because the EPA Assistant Administrator for Enforcement has the authority to advise a source that the government will not sue the source for taking certain actions during an emergency. Commenters said that this enforcement discretion approach has provided prompt, flexible relief that is tailored to the needs of the particular emergency and the communities being served and is only utilized where the relief will address the particular emergency at hand.
Commenters added that this enforcement discretion approach is consistent with the CAA's mandate that emission limits apply continuously and provide safeguards against abuse. One commenter stated that emergencies happen rarely and typically last for short periods, that the proposed percentage electric sales threshold would allow a source to operate at its full rated capacity for up to 2,920 hours per year without triggering applicability, and that the potential occurrence of grid emergencies would represent a tiny fraction of this time. Another commenter stated that no emergency short of large scale destruction of power generating capacity by terrorism, war, accident, or natural disaster could justify operating a peaking unit above a 10-percent capacity factor on a 3-year rolling average.
In response to the EPA's request for comments on whether the proposed applicability requirements that retrospectively look back at actual events (
Some commenters opposed the proposed retrospective applicability criteria related to actual output supplied during a preceding compliance period because EGUs must know what performance standards will apply to them during the licensing process, and such criteria do not allow the permitting authority and the public to know in advance whether an emission standard applies to a proposed new unit. Other commenters said that EGUs undergoing permitting should be allowed to request limits in their operating permit conditions in order to remain below the applicability thresholds, as this methodology is consistent with the pre-construction permitting requirements in many federally approved SIPs and the current approach under the Title V permitting program.
Many commenters stated a preference for the “proposed applicability approach” over the “broad applicability approach.” These commenters did not think it was necessary to require non-base load or multi-fuel-fired combustion turbines to be subject to emission standards. They stated that there is no justification for imposing burdensome monitoring, reporting, and recordkeeping requirements that would have no environmental benefit (
In contrast, to preserve the discretion of state planners under section 111(d), many other commenters supported the broad applicability approach and the inclusion of new simple cycle units within the scope of the section 111(b) emission standards so that similar, existing simple cycle units could be subject to the 111(d) standards. Numerous other commenters stated that all units that sell electricity to the grid should be subject to a standard, including simple cycle units, because they view the utility grid as a single integrated system and that doing so may simplify development of future frameworks for cost-effective carbon reductions from existing units, such as frameworks based on system-wide approaches.
Based on our consideration of the comments received related to the proposed applicability criteria and practical implementation issues, we are revising how those criteria will be implemented. The final applicability criteria for combustion turbines are generally consistent with the broad applicability approach on which we solicited comment. Section VIII of this preamble presents each proposed applicability criterion together with the form of the criterion in the final rule. The final general applicability framework includes the proposed criteria based on the combustion turbine's base load rating and the combustion turbine's total electric sales capacity. The final general applicability framework also includes multiple exemptions that are relevant to combustion turbines: combustion turbines that are not connected to natural gas pipelines; CHP facilities with federally enforceable limits on total electric sales; dedicated non-fossil units with federally enforceable limits on the use of fossil fuels; and municipal waste combustors and incineration units.
The final applicability framework reflects multiple variations from the proposal that are responsive to public comments. First, consistent with the broad applicability approach, we are finalizing the percentage electric sales and natural gas-use thresholds as subcategorization criteria instead of as applicability criteria. In addition, for non-CHP combustion turbines, we are eliminating the proposed 219,000 MWh total electric sales criterion. Finally, we are eliminating the proposed “constructed for the purpose of” qualifier for the total and percentage electric sales criteria. We are also not finalizing CO
The EPA agrees with commenters that the NSPS applicability framework should be structured so that permitting authorities, the regulated community, and the public can determine what standards apply prior to a unit having commenced construction. With this in mind, the EPA has concluded that the proposed fossil fuel-use, natural gas-use, percentage electric sales, and total electric sales applicability criteria for combustion turbines are not ideal approaches. Because applicability determinations based on these criteria could change from year to year (
Further, from a practical implementation standpoint, existing permitting rules generally require pre-construction permitting authorities to include enforceable conditions limiting operations such that unaffected units will not trigger applicability thresholds. Such conditions are often called “avoidance” or “synthetic minor” conditions, and these conditions typically include ongoing monitoring, recordkeeping, and reporting requirements to ensure that operations remain below a particular regulatory threshold.
The following sections provide further discussion of the final general applicability criteria and the rationale for changing certain proposed applicability criteria to subcategorization criteria.
We are retaining the applicability criterion that a combustion turbine must be capable of combusting more than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel. We revised the proposed 73 MW form of the base load rating criterion to 260 GJ/h because some commenters misinterpreted the 73 MW form (which is mathematically equivalent to 250 MMBtu/h) as the electrical output rating of the generator. This change is a non-substantive unit conversion intended to limit misinterpretation. While some commenters suggested that we expand this applicability criterion to cover smaller EGUs as well, we did not propose to cover smaller units. Because smaller units emit relatively few CO
The proposed 219,000 MWh total sales criterion was based on a 25 MW unit operating at base load the entire year (
Commenters generally opposed the proposed percentage electric sales criterion approach because it was based in part on actual electric sales, meaning applicability could change periodically (
The first approach is not practical, however, because new combustion turbines could avoid applicability by simply not having a permit restriction at all. Moreover, even if a combustion turbine were subject to the restriction, it could violate its permit if it did not operate enough to sell the requisite amount of electricity. This would be nonsensical, especially because system demand would not always be sufficient to allow all permitted units to operate above the threshold. Therefore, we rejected the first permitting approach.
In contrast, the second approach would be a viable method for identifying and exempting peaking units from applicability. However, there are multiple drawbacks to such an applicability approach. First, this approach would subject those turbines without a permit restricting electric sales to the final emission standards, which raises concerns as to whether turbines with lower actual sales could achieve the standards. For example, new NGCC units tend to dispatch prior to older existing units and will generally operate for extended periods of time near full load and sell electricity above the percentage electric sales threshold. However, as NGCC units age, they tend to start and stop more frequently and operate at part load. Yet, even if these units sell below the percentage electric sales threshold, they would still be affected units if they did not take a permit restriction. As commenters noted, part-load operation and frequent starts and stops can reduce the efficiency of a combustion turbine. While we are confident that our final standards for base load natural gas-fired combustion turbines can be achieved by units serving either base or intermediate load, we are not as confident that affected NGCC units that might someday be operated as non-base load units (
More importantly, however, we are concerned that using a permitting approach for the percentage electric sales criterion would create problems due to the interaction between 111(b) and 111(d). Under the second permitting approach we considered, units with low electric sales would be excluded from applicability, while units with high electric sales would be included. While these low-electric sales units would generally be simple cycle combustion turbines and the high-electric sales units would generally be NGCC combustion turbines, this would not always be the case. In contrast, we are finalizing an applicability approach in the 111(d) emission guidelines that is based on a combustion turbine's design characteristics rather than electric sales. Simple cycle combustion turbines are excluded from applicability, while NGCC units are included. As a result, the universe of sources covered by the 111(b) standards would not necessarily be the same universe of sources covered by the 111(d) standards.
To resolve this issue, we considered whether we could change the 111(d) applicability criteria to be based on historical operation rather than design characteristics. For example, if an existing combustion turbine had historically sold less than one-third of its potential output to the grid, then it would be exempt from the emission guidelines. However, many existing NGCC units have historically sold less than this amount of electricity, meaning that they would not be subject to the rule. We ran into similar issues when considering other thresholds. For example, a percentage electric sales threshold of 10 percent would still exempt roughly 5 percent of existing NGCC units from 111(d), while simultaneously raising achievability concerns with the 111(b) standard. Moreover, even if we had finalized 111(d) applicability criteria based on historical operations, existing NGCC units could have decided to take a permit restriction limiting their electric sales going forward to avoid applicability. Under any of these scenarios, our goals with respect to 111(d) would not be accomplished.
To avoid this result, the EPA has concluded that it is appropriate to finalize the broad applicability approach and set standards for combustion turbines regardless of what percentage of their potential electric output they sell to the grid. To accommodate the continued use of simple cycle and fast-start NGCC combustion turbines for peaking and cycling applications, however, the EPA has subcategorized natural gas-fired combustion turbines based on a variation of the proposed percentage electric sales criterion. Specifically, and as explained in more detail in Section IX.B.2, we are finalizing the sliding-scale approach on which we solicited comment.
Similar to the proposed electric sales criteria, commenters generally opposed the proposed natural gas-use criterion being based on actual operating parameters. As with the electric sales criteria, the EPA agrees that applicability that can switch periodically due to operating parameters is not ideal. The EPA evaluated two approaches for implementing the intent of the proposed natural gas-use criterion (
In light of these issues, the EPA has concluded that permit restrictions are not an ideal approach to distinguishing between natural gas-fired and multi-fuel-fired combustion turbines and are finalizing a variation of the broad applicability approach. The EPA has concluded that the only practical approach to implement the natural gas-use criterion is to look at the turbine's physical ability to burn natural gas. Therefore, we are not finalizing CO
We are finalizing a variation of the broad applicability approach for combustion turbines where the percentage electric sales and natural gas-use criteria serve as thresholds that distinguish between three subcategories. These subcategories are base load natural gas-fired units, non-base load natural gas-fired units, and multi-fuel-fired units. Under the final subcategorization approach, multi-fuel-fired combustion turbines are distinguished from natural gas-fired turbines if fuels other than natural gas (
This section describes comments we received regarding the proposed size-based subcategories and our rationale for not finalizing them. In addition, it describes comments we received regarding sales-based subcategories and our rationale for adopting the sliding scale to distinguish between subcategories. Finally, it describes comments we received regarding fuel-based subcategories and our rationale for adopting fuel-based subcategories.
At proposal, the EPA identified two size-based subcategories: (1) large natural gas-fired stationary combustion turbines with a base load rating greater than 850 MMBtu/h and (2) small natural gas-fired stationary combustion turbines with a base load rating of 850 MMBtu/h or less. The EPA received numerous comments regarding our proposal to subcategorize combustion turbines by size. Some commenters agreed with the 850 MMBtu/h cut-point between large and small units, some suggested increasing it to 1,500 MMBtu/h, and others suggested eliminating size-based subcategorization altogether. For example, some commenters stated that the 850 MMBtu/h cut-point was inappropriate because it was originally calculated based on NO
In contrast, other commenters said that differentiation between small and large combustion turbines was not justified at all because many of the same efficiency technologies that reduce the emission rates of larger units could be incorporated into smaller units (
After evaluating these comments, the EPA has decided not to subcategorize combustion turbines based on size for several reasons. First, the heat input values listed in
Second, commenters suggested that a cut-point of 1,500 MMBtu/h reflects when more efficient technologies become available. However, when we reviewed actual operating data and design data, we only found a relatively weak correlation between turbine size and CO
Finally, the EPA has concluded that, while certain smaller NGCC designs may be less efficient than larger NGCC designs, most existing small units have demonstrated emission rates below the range of emission rates on which we solicited comment. We have concluded that the lower design efficiencies of some small NGCC units are primarily related to model-specific design choices in both the turbine engine and HRSG, not an inherent limitation in the ability of small NGCC units to have comparable efficiencies to large NGCC units. Specifically, manufacturers could improve the efficiency of the turbine engine by using turbine engines with higher firing temperatures and high compression ratios and could improve the efficiency of the steam cycle by switching from single or double-pressure steam to triple-pressure steam and adding a reheat cycle. For all of these reasons, we have decided against subcategorizing combustion turbines based on size. Our rationale for setting a single standard for small and large combustion turbines is explained in more detail in Section IX.D.3.a below.
As described above in Section IX.A.3.c, the final applicability criteria do not include an exemption for non-CHP units based on actual electric sales or permit restrictions limiting the amount of electricity that can be sold. Instead, we are finalizing the percentage electric sales criterion as a threshold to distinguish between two natural gas-fired combustion turbine subcategories. The industry uses a number of terms to describe combustion turbines with different operating characteristics based on electric sales (
Numerous commenters supported three sales-based subcategories for peaking, intermediate load, and base load units. These commenters said that each subcategory should be distinguished by annual hours of operation and that each should have a different BSER and emission standard. Other commenters opposed the tiered approach. These commenters said that separate standards for different operating conditions would be complicated to implement and enforce, while providing few benefits. These commenters said that a tiered approach could also have the unintended consequence of encouraging less efficient technologies because it would create a regulatory incentive to install lower-capital-cost, less-efficient units that would operate under the percentage electric sales threshold instead of higher-capital-cost, more-efficient units that would operate above the threshold.
After evaluating these comments, the EPA has concluded that it is appropriate to adopt a two-tiered subcategorization approach based on a percentage electric sales threshold to distinguish between non-base load and base load units. While we agree with commenters that separate standards for peaking, intermediate, and base load units is attractive on the surface, we ultimately concluded that a three-tiered approach is not appropriate for several reasons. First, the increased generation from renewable sources that is anticipated in the coming years makes it very difficult to determine appropriate thresholds to distinguish among peaking, intermediate, and base load subcategories. Indeed, the boundaries between these demand-serving functions may blur or shift in the years to come. The task is further complicated because each transmission region has a different mix of generation technologies and load profiles with different peaking, intermediate, and base load requirements.
Second, there are only two distinct combustion turbine technologies—simple cycle units and NGCC units. In theory, the BSER for the intermediate load subcategory could be based on high-efficiency simple cycle units or fast-start NGCC units, but these are variations on traditional technologies and not necessarily distinct. Moreover, we do not have specific cost information on either high-efficiency simple cycle turbines or fast-start NGCC units, so our ability to make cost comparisons to conventional designs is limited.
Finally, even if we could identify appropriate sales thresholds to distinguish between peaking, intermediate load, and base load subcategories, we do not have sufficient information to establish a meaningful output-based standard for an intermediate load subcategory at this time. In the transition zone from peaking to base load operation (
Instead, as we explained above, we are finalizing two sales-based subcategories. To determine an appropriate threshold to distinguish between base load and non-base load units, the EPA considered the important characteristics of the combustion turbines that serve each type of demand. For non-base load units, low capital costs and the ability to start, stop, and change load quickly are key. Simple cycle combustion turbines meet these criteria and thus serve the bulk of peak demand. In contrast, for base load units, efficiency is the key consideration, while capital costs and the ability to start and stop quickly are less important. While NGCC units have relatively high capital costs and are less flexible operationally, they are more efficient than simple cycle units. NGCC units recover the exhaust heat from the combustion turbine with a HRSG to power a steam turbine, which reduces fuel use and CO
The challenge, however, is setting a threshold that will not distort the market. The future distinction between non-base load and base load units is unclear. For example, some commenters indicated that increased generation from intermittent renewable sources has created a perceived need for additional cycling and load following generation that will operate between the traditional roles of peaking and base load units. To fulfill this perceived need, some manufacturers have developed high-efficiency simple cycle turbines. These high-efficiency turbines have higher capital costs than traditional simple cycle turbine designs, but maintain similar flexibilities, such as the ability to start, stop, and change load rapidly. Other manufacturers have developed fast-start NGCC turbines to fill the same role. These newer NGCC designs have lower design efficiencies than NGCC designs intended to only operate as base load units, but are able to startup more quickly to respond to rapid changes in electricity demand. As a result of these new technological developments, both high-efficiency simple cycle and fast-start NGCC units can be used for traditional peaking applications, as well as for higher capacity applications, such as supporting the growth of intermittent renewable generation.
With the changing electric sector in mind, we set out to identify an appropriate percentage electric sales threshold to distinguish between non-base load and base load natural gas-fired units. Two factors were of primary importance to our decision. First, the threshold needed to be high enough to address commenters' concerns about the need to maintain flexibility for simple cycle units to support the growth of intermittent renewable generation. Second, the threshold needed to be low enough to avoid creating a perverse incentive for owners and operators to avoid the base load subcategory by installing multiple, less efficient turbines instead of fewer, more efficient turbines.
To determine the potential impact of intermittent renewable generation on the operation of simple cycle units, we examined the average electric sales of simple cycle turbines in the lower 48 states between 2005 and 2014 using information submitted to CAMD. We combined this data with information reported to the EIA on total in-state electricity generation, including wind and solar, from 2008 through 2014. We focused on data from the Southwest Power Pool (data approximated by EGUs in Nebraska, Kansas, and Oklahoma), Texas, and California. All of these regions have relatively large amounts of generation from wind and solar and experienced increases in the portion of total electric generation provided by wind and solar during the 2008-2014 period.
The portion of in-state generation from wind and solar in the Southwest Power Pool increased from 3 to 16 percent between 2008 and 2014. The average growth rate of wind and solar was 28 percent, while overall electricity demand grew 1 percent annually on average. Based on statements in some of the comments, we expected to see a large change in the operation of simple cycle turbines in this region. However, the average electric sales from simple cycle turbines only increased at an annual rate of 1.7 percent, and remained essentially unchanged at 3 percent of potential electric output between 2008 and 2014. Total generation from simple cycle turbines in the Southwest Power Pool increased slightly more, at an annual rate of 2.5 percent, which was the result of additional simple cycle capacity being added to address increased electricity demand.
This lack of a significant change in the operation of simple cycle turbines could be explained by the Southwest Power Pool's relatively large amount of exported power. If most of the region's renewable generation was being exported, the intermittent nature of this power would primarily impact other transmission regions. An alternate explanation, however, is that other generating assets are flexible enough to respond to the intermittent nature of wind and solar generation and that simple cycle turbines are not necessary to back up these assets to the degree some commenters suggested. If this is the case, then new simple cycle turbines may primarily continue to fill their historical role as peaking units going forward, while other technologies, such as fast-start NGCC units, may provide the primary back up capacity for new wind and solar.
The portion of in-state generation from wind and solar in Texas increased from 4 to 9 percent between 2008 and 2014. The average growth rate of wind and solar was 13 percent, while overall demand grew at an average rate of 2 percent annually. Similar to the Southwest Power Pool, the average electric sales of simple cycle turbines has remained relatively unchanged. In fact, the average electric sales of these turbines decreased at an annual rate of 1.1 percent. Total generation from simple cycle turbines increased at an annual rate of 6.6 percent, however, due to simple cycle capacity additions that occurred at approximately four times the rate one would expect from the growth in overall demand.
The most likely technologies to back up intermittent renewable generation have low incremental generating costs and can start up and stop quickly. Highly efficient simple cycle units meet these criteria. As such, the EPA has concluded that the most efficient simple cycle turbines in a given region are the most likely to support intermittent renewable generation. Focusing on these simple cycle turbines will address concerns raised by commenters about the future percentage electric sales of highly efficient simple cycle turbines and give an indication of the impact of increased renewable generation on non-base load units intended to back up wind and solar. There are two highly efficient intercooled simple cycle turbines installed in Texas. These two combustion turbines sell an average of 10 percent of their potential electric output annually, compared to an average of 3 percent for the remaining simple cycle turbines. No simple cycle
The portion of in-state generation from wind and solar in California increased from 3 to 11 percent between 2008 and 2014. The average growth rate of wind and solar was 25 percent, while overall demand has remained stable. The operation of simple cycle turbines in California has changed more significantly than in the other evaluated regions. The average electric sales from simple cycle turbines increased from 5.1 to 5.9 percent, an annual rate increase of 4.5 percent. As in Texas, considerable additional simple cycle capacity has been added in recent years. The total capacity of simple cycle turbines is increasing at 15 percent annually even though overall demand has remained relatively steady. In addition, the newest simple cycle turbines are operating at higher capacity factors than the existing fleet of simple cycle turbines, resulting in an average increase in generation from simple cycle turbines of 21 percent. Many of the new additions are intercooled simple cycle turbines that may have been installed with the specific intent to back up wind and solar generation.
The average electric sales for the intercooled turbines ranged from 3 to 25 percent, with a 7 percent average. No simple cycle turbines in California have sold more than one-third of their potential electric output on an annual basis. The operation of simple cycle turbines that existed prior to 2008 has not changed significantly. Average electric sales for these turbines increased at an annual rate of 0.1 percent. This indicates that support for new renewable generation is being provided by new units and not by the installed base of simple cycle units. These units are still serving their historical role of providing power during peak periods of demand.
Based on our data analysis, the proposed one-third electric sales threshold would appear to offer sufficient operational flexibility for new simple cycle turbines. Existing NGCC units, other generation assets, and demand-response programs are currently providing adequate back up to intermittent renewable generation. In the future, however, existing NGCC units will likely operate at higher capacity factors. They will therefore be less available to provide back up power for intermittent generation. In addition, the amount of power generated by intermittent sources is expected to increase in the future. Both of these factors could require additional flexibility from the remaining generation sources to maintain grid reliability.
Even though fast-start NGCC units, reciprocating internal combustion engines, energy storage technologies, and demand-response programs are promising technologies for providing back up power for renewable generation, none of them historically have been deployed in sufficient capacity to provide the potential capacity needed in the future to facilitate the continued growth of renewable generation. While we anticipate that state and federally issued permits for new electric generating sources will consider the CO
Specifically, we have concluded that a percentage electric sales threshold based on a unit's design net efficiency at standard conditions is appropriate. This is the sliding-scale approach on which we solicited comment. Several commenters supported this approach because it provides sufficient operational flexibility for new simple cycle and fast-start NGCC combustion turbines and simultaneously promotes the installation of the most efficient generating technologies. By allowing more efficient turbines to sell more electricity before becoming subject to the standard for the base load subcategory, the sliding scale should reduce the perverse incentive for owners and operators to install more lower-capital-cost, less-efficient units instead of fewer higher-capital-cost, more-efficient units. At the same time, the sliding scale should incentivize turbine manufacturers to design higher efficiency simple cycle turbines that owners and operators can run more frequently.
The net design efficiencies for aeroderivative simple cycle combustion turbines range from approximately 32 percent for smaller designs to 39 percent for the largest intercooled designs. The net design efficiencies of industrial frame units range from 30 percent for smaller designs to 36 percent for the largest designs. These efficiency values follow the methodology the EPA has historically used and are based on the higher heating value (HHV) of the fuel. In contrast, combustion turbine vendors in the U.S. often quote efficiencies based on the lower heating value (LHV) of the fuel. The LHV of a fuel is determined by subtracting the heat of vaporization of water vapor generated during combustion of fuel from the HHV. For natural gas, the LHV is approximately 10 percent lower than the HHV. Therefore, the corresponding LHV efficiency ranges would be 35 to 44 percent for aeroderivative designs and 33 to 40 percent for frame designs. We considered basing the percentage electric sales threshold on both the HHV and LHV. The EPA typically uses the HHV, but in light of commenters' concerns regarding uncertainty in the operation of non-base load units in the future, we opted to be conservative and use the LHV efficiency.
We anticipate that high-efficiency simple cycle and fast-start NGCC turbines will make up the majority of new capacity intended for non-base load applications. Based on the sliding-scale approach, owners and operators of new simple cycle combustion turbines will be able to sell between 33 to 44 percent of the turbine's potential electric output. Our analysis showed that 99.5 percent of existing simple cycle turbines have not sold more than one-third of their potential electric output on an annual basis. In addition, 99.9 percent of existing simple cycle turbines have not sold more than 36 percent of their potential electric output on an annual basis. The two simple cycle turbines that exceeded the 36 percent threshold had annual electric sales of 39 and 45 percent and are located in Montana and New York, respectively. As noted earlier, the most efficient simple cycle turbine currently available is 44 percent efficient and would accommodate the operations at the Montana facility. The only existing simple cycle turbine that exceeded the maximum allowable percentage electric sales threshold of 44 percent, which is based on current simple cycle designs, sold an abnormally high amount of electricity in 2014. It is possible that this unit was operating under emergency conditions. As explained below, the incremental generation due to the emergency would not have counted against the percentage electric sales threshold.
We are capping the percentage electric sales threshold at 50 percent of potential electric output for multiple reasons. First, NGCC emission rates are
Finally, the EPA solicited comment on excluding electricity sold during system emergencies from counting towards the percentage electric sales threshold. After considering the comments, we have concluded that this exclusion is necessary to provide flexibility, maintain system reliability, and minimize overall costs to the sector. We disagree with commenters that suggested that the EPA's existing enforcement discretion would be a viable alternative. An enforcement discretion-based approach would not provide certainty to the regulated community, public, and regulatory authorities on the applicability of the emission standards, which is a primary reason why we are finalizing the broad applicability approach. Moreover, system emergencies are defined events, so commenters' fears that the exclusion will be subject to abuse are overstated. Therefore, electricity sold during hours of operation when a unit is called upon to operate due to a system emergency will not be counted toward the percentage electric sales threshold. However, electricity sold by units that are not called upon to operate due to a system emergency (
In summary, the EPA is finalizing the percentage electric sales criterion as a threshold to distinguish between two natural gas-fired combustion turbine subcategories. Specifically, all units that have electric sales greater than their net LHV design efficiencies (as a percentage of potential electric output) are base load units. All units that have electric sales less than or equal to their net LHV design efficiencies are non-base load units. We are capping the percentage electric sales threshold at 50 percent of potential electric output. This sliding-scale approach will limit the operation of the least efficient units, provide flexibility for renewable energy growth, and incentivize the development of more efficient simple cycle units.
As described in Section IX.A.3.d, we are finalizing a version of the broad applicability approach. Under the broad applicability approach, the EPA solicited comment on a subcategorization approach based in part on natural gas-use. We received few comments on this issue. One of the comments we did receive was that combustion turbines that burn fuels other than natural gas have higher CO
For the reasons described in the applicability section, we have decided to set emission standards for all combustion turbines capable of burning natural gas, regardless of the actual fuel burned, to avoid the practical problems that would have arisen under the proposed approach. However, as commenters explained, multi-fuel-fired combustion turbines cannot achieve the emission standards achieved by natural-gas fired turbines. For this reason, it would not be reasonable to require affected EGUs to comply with a standard based on the use of natural gas during periods when significant quantities of non-natural gas fuels are being burned. If we did not subcategorize, owners and operators would not be able to combust other fuels in their turbines, including process gas, blast furnace gas, and petroleum-based liquid wastes, which might otherwise be wasted. In addition, without the ability to burn back up fuels during natural gas curtailments, grid reliability could be jeopardized. Therefore, we are finalizing a separate fuel-based subcategory for multi-fuel-fired combustion turbines. To distinguish between this subcategory and the natural gas-fired subcategories, we are using the same threshold as proposed. Specifically, combustion turbines that burn ninety percent or less natural gas on a 12-operating-month rolling average basis will be included in this subcategory and subject to a separate emission standard, which is discussed in Section IX.D.3.d.
This section summarizes the EPA's proposed BSER determinations for stationary combustion turbines, provides a summary of the comments we received, and explains our final BSER determinations for each of the three subcategories we are now finalizing. For natural gas-fired stationary combustion turbines operating as base load units, we proposed and are finalizing the use of NGCC technology as the BSER. For the other two subcategories of affected combustion turbines—non-base load natural gas-fired combustion turbines and multi-fuel-fired combustion turbines—we are finalizing the use of clean fuels as the BSER.
We considered three alternatives in evaluating the BSER for base load natural gas-fired combustion turbines: (1) Partial CCS, (2) high-efficiency simple cycle aeroderivative turbines, and (3) modern, efficient NGCC turbines. We rejected partial CCS as the BSER because we concluded that we did not have sufficient information to determine whether implementing CCS for combustion turbines was technically feasible. We rejected high-efficiency simple cycle aeroderivative turbines as the BSER because this standalone technology does not provide emission reductions and generally is more expensive than NGCC technology for base load applications. In contrast, NGCC is the most common type of new fossil fuel-fired EGU currently being planned and built for generating base load power. NGCC is technically feasible, and NGCC units are currently the lowest-cost, most efficient option for new base load fossil fuel-fired power generation. After considering the options, the EPA proposed to find that modern, efficient NGCC technology is the BSER for base load natural gas-fired combustion turbines.
For non-base load natural gas-fired units and multi-fuel-fired units, we did not propose a specific BSER or associated numeric emission standards, but instead solicited comment on these issues.
This section summarizes the differing comments submitted on the proposed BSER for base load natural gas-fired combustion turbines. Some commenters supported partial CCS as the BSER, others supported advanced NGCC
Some commenters stated that our proposed BSER analysis for stationary combustion turbines was inconsistent with our proposed BSER analysis for coal-fired units. They stated that the EPA had determined that the use of CCS was feasible for coal-fired generation based on current CCS projects under development at coal-fired generating stations, but did not come to the same conclusion for combustion turbines. These commenters stated that CO
Some commenters referenced the Northeast Energy Association NGCC plant in Bellingham, MA, which operated from 1991-2005 with 85-95 percent carbon capture on a 320 MW unit for use in the food and beverage industry, that was referred to in the proposal. This plant captured 330 tons of CO
These commenters also referenced reports authored by DOE, NETL, the Clean Air Task Force (CATF), CCS Task Force, ICF Inc., and Global CCS Institute, suggesting that, because CCS technology for NGCC is included in these reports, it is adequately demonstrated. Some commenters referred to a DOE/NETL study that suggested that the cost of CCS for NGCC units would be more cost-effective than for coal-fired EGUs. One non-industry commenter emphasized that a technology does not have to be in use to be considered adequately demonstrated.
In addition, some commenters disagreed with the EPA's decision to treat combustion turbines differently than coal-fired units with respect to CCS on the basis that combustion turbines startup, shutdown, and cycle load more frequently than coal-fired units. According to these commenters, the operating characteristics of combustion turbines do fluctuate, but so do those of coal-fired units. Another commenter said that even if NGCC operations vary more than they do for coal-fired units, it is not an impediment to using CCS because combustion turbine operators could bypass the carbon capture system during startup and shutdown modes (which are typically shorter and less intensive efforts compared to the startup or shutdown of a coal facility) and then employ the carbon capture system when operating normally. One commenter stated that most future base load fossil fuel-fired generation will be NGCC and that not making CCS the BSER for NGCC would result in significant CO
Other commenters supported the EPA's determination that CCS is not the BSER for combustion turbines. These commenters said that CCS is not adequately demonstrated for combustion turbines because none are currently operating, under construction, or in the advanced stages of development. They also noted that CCS would have to be demonstrated for the range of facilities included in the regulated source category, which they alleged includes both simple cycle and NGCC units. They specifically noted that the Bellingham, MA demonstration facility was not a full-scale commercial NGCC power plant operating with CCS.
These commenters agreed with the EPA that CCS does not match well with the operating flexibilities of NGCC and simple cycle units. They agreed with the EPA that frequent cycling restricts the efficacy of CCS on these units, a problem which would only get worse as more renewable energy sources are integrated into the grid. These commenters added that NGCC units operate differently than coal-fired units because the former start, stop, and cycle frequently, whereas the latter tend to operate at relatively steady loads and do not start and stop frequently. They stated that even if technical barriers could be overcome, the application of CCS to combustion turbines would be more costly (compared to the application of CCS to coal-fired units) on a dollars-per-ton basis. In addition, these commenters said that other industries' experience with CCS could not be transferred to NGCC units due to differences in flue gas CO
Some commenters stated that CAA section 111(a) requires the EPA to account not only for the cost of achieving emission reductions, but also for impacts on energy requirements and the environment. The commenters cited to
Some commenters stated that the proposed BSER analysis should have reflected the emission rates achieved by the latest designs deployed at advanced, state-of-the-art NGCC installations. These commenters stated that advanced NGCC technologies are the best system
Many commenters opposed the EPA's proposal to set emission standards for combustion turbines based on their function rather than based on their design. These commenters stated that the EPA's determination that NGCC technology is the BSER for base load natural gas-fired combustion turbines would apply equally to simple cycle turbines if they sell electricity in excess of the percentage electric sales threshold. They pointed to the word “achievable” in CAA section 111(a)(1) and stated that applying an emission standard based on NGCC technology to simple cycle units was legally indefensible because simple cycle units cannot achieve emission rates as low as NGCC units. In contrast, many other commenters agreed with the EPA's basic approach and stated that NGCC technology should be the BSER for base-load functions, while simple cycle technology should be the BSER for peak-load functions.
Multiple commenters suggested that high efficiency simple cycle or fast-start NGCC technologies should be the BSER for non-base natural gas-fired load units. They explained that high efficiency simple cycle units and fast-start NGCC units are actually more efficient when serving non-base load demand than NGCC units that are designed strictly for base load operation. Some commenters also suggested that we should subcategorize multi-fuel-fired combustion turbines, but did not provide any specific technologies that should be considered in the BSER analysis.
After our evaluation of the comments and additional analysis, we identified the BSER for each subcategory of combustion turbine that we are finalizing: base load natural gas-fired units, non-base load natural gas-fired units, and multi-fuel-fired units.
As described in the proposal, we evaluated CCS, NGCC, and high-efficiency simple cycle combustion turbines as the potential BSER for this subcategory. We selected NGCC as the BSER because it met all the BSER criteria. This section describes our response to issues raised by commenters and our rationale for maintaining that NGCC is the BSER for base load natural gas-fried combustion turbines.
Some commenters stated that CCS could be applied equally to both coal-fired and natural gas-fired EGUs. To support this conclusion, the commenters pointed to a retired NGCC-with-CCS demonstration project, as well as a few overseas projects and projects in the early stages of development. While we have concluded that these commenters made strong arguments that the technical issues we raised at proposal could in many instances be overcome, we have concluded that there is not sufficient information at this time for us to determine that CCS is adequately demonstrated for all base load natural-gas fired combustion turbines.
While the commenters make a strong case that the existing and planned NGCC-with-CCS projects demonstrate the feasibility of CCS for NGCC units operating at steady state conditions, many NGCC units do not operate this way. For example, the Bellingham, MA and Sumitomo NGCC units cited by the commenters operated at steady load conditions with a limited number of starts and stops, similar to the operation of coal-fired boilers.
Notably, the Department of Energy has not yet funded a CCS demonstration project for a NGCC unit, and no NGCC-with-CCS demonstration projects are currently operational or being constructed in the U.S. In contrast, multiple CCS demonstration projects for coal-fired units are in various stages of development throughout the U.S., and a full-capture system is in operation at the Boundary Dam facility in Canada. See Sections V.E and D above.
One commenter suggested that not having CCS as the BSER for combustion turbines would ultimately halt the development of CCS in the U.S. We disagree. A number of coal-fired power plants are currently being built with CSS, while some existing plants are considering CCS retrofits. Moreover, the NSPS sets the minimum level of control for new sources. We expect that state air agencies and other air permitting authorities will evaluate CCS when permitting new NGCC power plants, taking into consideration case-specific parameters, like operating characteristics, to determine whether CCS could be BACT or LAER in specific instances. While the NGCC-with-CCS units that currently are in the planning stages do not provide us with enough assurance to determine that CCS is adequately demonstrated for combustion turbines, it is our expectation that these units and others to come will provide additional information for both permitting reviews and the next NSPS review in eight years.
Regarding the advanced NGCC technologies advocated by several commenters, the EPA has concluded
As we explained in the proposal, NGCC technology meets all of the BSER criteria. For base load functions, NGCC units are technically feasible, cost-effective (indeed, less expensive than simple cycle combustion turbines), and have no adverse energy or environmental impacts. Moreover, NGCC units reduce emissions because they have a lower CO
Some commenters suggested that the costs and efficiency impacts of startup and shutdown events are higher for NGCC units than for simple cycle units. Consequently, we refined the LCOE costing approach used at proposal by adding these additional costs and efficiency impacts to our cost comparison. Even accounting for these new costs and impacts, we found that NGCC technology results in a lower cost of electricity than simple cycle technology when a unit's electric sales exceed approximately one-third of its potential electric output. The final percentage electric sales criterion for the base load natural gas-fired combustion turbine subcategory is based on the sliding scale. This means that the dividing line between the base load subcategory and the non-base load subcategory will change depending on a unit's nameplate design efficiency. For a conventional simple cycle turbine, the base load subcategory will begin at around 33 percent electric sales, while for a newer fast-start NGCC turbine, the base load subcategory will begin at approximately 50 percent electric sales. Anywhere within this range, our cost calculations have shown that NGCC technology is more cost-effective than simple cycle technology. Therefore, we are finalizing our determination that modern, efficient NGCC technology is the BSER for base load natural-gas fired combustion turbines.
Many commenters mistakenly thought that the EPA proposed to require some simple cycle combustion turbines to meet an emission standard of 1,000 lb CO
To identify the BSER for non-base load natural gas-fired units, we evaluated a range of technologies, including partial CCS, high-efficiency NGCC technology designed for base load applications, fast-start NGCC, high-efficiency simple cycle units (
While CCS would result in emission reductions and promote the development of new technology, we concluded that CCS does not meet the BSER criteria because the low capacity factors and irregular operating patterns (
We have also concluded that the high-efficiency NGCC units designed for base load applications do not meet any of the BSER criteria for non-base load units. First, non-base load units need to be able to start and stop quickly, and NGCC units designed for base load applications require relatively long startup and shutdown periods. Therefore, conventional NGCC designs are not technically feasible for the non-base load subcategory. Also, non-base load units operate less than 10 percent of the time on average. As a result, conventional NGCC units designed for base load applications, which have relatively high capital costs, will not be cost-effective if operated as non-base load units. In addition, it is not clear that a conventional NGCC unit will lead to emission reductions if used for non-base load applications. As some commenters noted, conventional NGCC units have relatively high startup and shutdown emissions and poor part-load efficiency, so emissions may actually be higher compared with simple cycle technologies that have lower overall design efficiencies but better cycling efficiencies. Finally, requiring conventional NGCC units as the BSER for non-base load combustion turbines would not promote technology because these units would not be fulfilling their intended role. In fact, it could hamper the development of technologies with lower design efficiencies that are specifically designed to operate efficiently as non-base load units (
Compared to conventional NGCC technology, fast-start NGCC units have lower design efficiencies, but are able to start and ramp to full load more quickly. Therefore, it is possible that requiring fast-start NGCC as the BSER for non-base load units would result in emission reductions and further promote the development of fast-start NGCC technology, which is relatively new and advanced. However, because the
High-efficiency simple cycle turbines are primarily used for peaking applications. High-efficiency simple cycle turbines often employ aeroderivative designs because they are more efficient at a given size and are able to startup and ramp to full load more quickly than industrial frame designs. Requiring high-efficiency simple cycle turbines as the BSER could result in some emission reductions compared with conventional simple cycle turbines. It would also promote technology development by incentivizing manufacturers to increase the efficiency of their simple cycle turbine models. However, aeroderivative designs have higher initial costs that must be weighed against the specific peak-load profiles anticipated for a particular new non-base load unit. Many utility companies have elected to install the heavier industrial frame turbines because the ramping capabilities of aeroderivative turbines are not required for their system demand profiles (
The final option that we considered for the BSER was clean fuels, specifically natural gas with a small allowance for distillate oil. The use of clean fuels is technically feasible for non-base load units. Based on available EIA data,
To identify the BSER for multi-fuel-fired units, we again evaluated CCS, NGCC technology, high-efficiency simple cycle units (
While CCS would result in emission reductions and the promotion of technology, we concluded that CCS does not meet the BSER criteria because multi-fuel-fired units tend to start, stop, and operate at part load frequently. Also, there are impurities and contaminants in some alternate fuels which make the technical challenges of applying CCS to multi-fuel-fired units greater than for natural gas-fired units.
In regards to NGCC technology, we have concluded that it is technically feasible, would result in emission reductions, is cost-effective, and would promote the development of technology. However, a BSER determination based on the use of NGCC technology could pose challenges for facilities operating in remote locations and certain industrial facilities. In remote locations, the construction of a NGCC facility is often not practical because it requires larger capital investments and significant staffing for construction and operation. In contrast, simple cycle turbines are cheaper and can be operated with minimal staffing. Also, many industrial facilities do not have the space available to build a HRSG and the associated cooling tower. Therefore, requiring NGCC as the BSER could have unforeseen energy impacts at these types of facilities. Moreover, these same kinds of facilities also burn by-product fuels. Faced with a decision to install an NGCC unit, these facilities might seek alternative energy options, which could lead to increased flaring or venting of by-product fuels because they are no longer being burned onsite for energy recovery. Therefore, in light of these potential energy and non-air quality impacts, we have concluded that NGCC technology is not the BSER for multi-fuel-fired combustion turbines.
Similarly, while high-efficiency simple cycle turbines would result in emission reductions and promote the advancement of this technology, we are not confident that high-efficiency simple cycle units are technically feasible or cost-effective for this subcategory. Aeroderivative turbines are not as flexible with regards to what fuels that can be burned. Because by-product fuels vary in composition, it is not clear that all by-products fuels could be burned in a high-efficiency simple cycle turbine. In addition, even if a by-product fuel could be burned in an aeroderivative turbine, we do not have information on the potential for increased maintenance costs, so we cannot determine whether using high-efficiency simple cycle turbines would be cost-effective.
The final option that we considered for the BSER was clean fuels. The use of clean fuels is technically feasible and cost-effective. The use of clean fuels also provides an environmentally beneficial alternative to the flaring or venting of by-product fuels and limits the use of dirtier fuels with higher CO
We are finalizing emission standards for three subcategories of combustion turbines. Specifically, units that sell electricity in excess of a threshold based on their design efficiency and that burn more than 90 percent natural gas (
For large newly constructed, modified, and reconstructed stationary combustion turbines (base load rating greater than 850 MMBtu/h), we proposed an emission standard of 1,000 lb CO
In addition, we solicited comment on increasing the size distinction between large and small stationary combustion turbines to 900 MMBtu/h to account for larger aeroderivative designs; increasing the size distinction to 1,000 MMBtu/h to account for future incremental increases in base load ratings; increasing the size distinction to between 1,300 to 1,800 MMBtu/h; and eliminating the size subcategories altogether. To account for potential reduced efficiencies when units are not operating at base load, we also solicited comment on whether a separate, less stringent standard should be established for non-base load combustion turbines.
As described previously, we are not finalizing the size-based subcategories that we proposed and instead are finalizing emission standards for sales- and fuel-based subcategories. Specifically, we are finalizing emission standards for three subcategories of stationary combustion turbines: base load natural-gas fired units, non-base load natural gas-fired units and multi-fuel-fired units. The relevant comments concerning the emission standards for the first two subcategories are discussed below. Any comments we received supporting tiered emission standards are included in the discussion of non-base load natural gas-fired units. We did not receive comments on an appropriate emission standard for multi-fuel-fired units.
Many commenters stated that the proposed emission standards did not properly take into account the losses in efficiency that occur due to long-term degradation over multiple decades, operation at non-base load conditions (load cycling, frequent startups and shutdowns, and part-load operations), site-specific factors such as ambient conditions and cooling technology, and secondary fuel use (
Some commenters stated that the proposed standards were derived by looking at emissions data from years with historically low natural gas prices. They surmised that the NGCC units were taking advantage of these prices by running at historically high capacity factors and concluded that the efficiencies and CO
Some commenters indicated that, during startup, combustion turbines must be operated at low load for extended periods to gradually warm up the HRSG to minimize thermal stresses on pressure vessels and boiler tubes. During these startup periods, significant CO
Many commenters said that site-specific factors can often preclude operators from achieving design efficiencies based on ISO conditions. These factors include high elevations, high ambient temperatures, and cooling system constraints. They stated that local water temperatures can impact condenser operating pressure and heat rates. They also said that areas with limited water resources could require systems that rely on air-cooled condensers, which cannot achieve thermal efficiencies comparable to water-cooled plants. These commenters stated that the final rule should include provisions for addressing site-specific constraints that preclude individual affected EGUs from achieving the emissions rates achieved on average by other sources.
Some commenters stated that the proposed standards for modified and reconstructed combustion turbines would foreclose future opportunities for operators to undertake projects to restore the performance of both degraded units subject to the NSPS and existing, pre-NSPS units. They said that it is not possible to bring older combustion turbines (built prior to the year 2000) up to the efficiency levels of modern units because many newer technological options that deploy higher temperatures are not available for pre-2000 combustion turbines.
Commenters from the power sector generally supported increasing the standards to 1,100 lb CO
Conversely, some commenters stated that the proposed standards for combustion turbines do not reflect the emission rates that are achievable by
Many commenters stated that the EPA cannot finalize “no emission standard” for non-base load units, which the EPA solicited comment on in the broad applicability approach. They argued that this approach was not consistent with the definition of “standard of performance” in CAA section 111(a)(1), which requires there to be an “emission limitation” that reflects a “system of emission reduction.” Some commenters recommended that non-base load units should be subject to work practice standards, such as operating safely with good air pollution control practices, including CO
In evaluating the achievability of the base load natural gas-fired emission standard, we focused on three types of data. Specifically, we looked at existing NGCC emission rates, recent PSD permit limits for CO
Since the standards were proposed, the EPA has expanded the NGCC emission rate analysis that supported the proposed emission standards to include emissions information for NGCC units that commenced operation in 2011, 2012, and 2013, and updated the emissions data to include emissions through 2014. In our analysis, we evaluated 345 NGCC units with online dates ranging from 2000 to 2013. The analysis included emissions data from 2007 to 2014 as submitted to the EPA's CAMD. The average maximum 12-operating-month CO
Consistent with our proposed size-based subcategories, we also reviewed the emissions data for small and large NGCC units separately. For small units, we evaluated emissions data from 17 NGCC units with heat input ratings of 850 MMBtu/h or less. These units had an average maximum 12-operating-month CO
For large units, the average maximum 12-operating-month emission rate was 895 lb CO
To evaluate degradation further, the EPA reviewed the emission rate information for the 55 oldest NGCC units in our data set (
We also evaluated the impact of elevation, ambient temperature, cooling type, and operating conditions (startups, shutdowns, and average run time per start) because commenters indicated that these could affect a unit's ability to achieve the standard. We saw little correlation between elevation or ambient temperature and emission rate. In addition, any correlation was relatively small and would have an insignificant impact on the ability of a unit to achieve the final standard. We identified 32 large NGCC units with dry cooling towers. The average maximum 12-operating-month emission rate for this group of units was 875 lb CO
In addition to evaluating existing NGCC emissions data, the EPA reviewed the CO
The remaining 28 permit limits were expressed in lb CO
Each of the permit limits discussed above that is 1,000 lb CO
Finally, we also reviewed NGCC design efficiency data and specifications submitted to
Because some commenters were concerned that smaller NGCC units will not be able to achieve the emission standard, we specifically considered the design rates for smaller units. For the 52 small units (base load rating of 850 MMBtu/h or less), the average design emission rate was 865 lb CO
We further refined our analysis by only considering the most efficient design for a given combustion turbine engine. For example, GE Energy Aeroderivative offers four design options for its LM2500 model-type, all with a rating of approximately 45 MW. The design emission rates for these various options range from 827 to 914 lb CO
After considering these three sources of information—actual NGCC emission rate data, PSD permit limits for NGCC facilities, and NGCC design information—we have concluded that a standard of 1,000 lb CO
We also expect multiple technology developments to further increase the performance of new base load natural gas-fired stationary combustion turbines. Vendors continue to improve the single cycle efficiency of combustion turbines. The use of more efficient combustion turbine engines improves the overall efficiency of NGCC facilities. In addition, existing smaller NGCC facilities were likely designed using single or dual pressure HRSGs without a reheat cycle. New designs can incorporate three pressure steam generators with a reheat cycle to improve the overall efficiency of the NGCC facility. Finally, additional technologies to reduce emission rates for new combustion turbines include CHP and integrated non-emitting technologies. For example, an NGCC unit that is designed as a CHP unit where ten percent of the overall output is useful thermal output would have an emission rate approximately five percent less than an electric-only NGCC. In sum, we believe that our final emission standards of 1,000 lb CO
We disagree with commenters that stated that reconstructed combustion turbines will not be able to achieve the proposed emission standards. For the reasons listed below, we have concluded that an existing base load natural-gas fired unit that reconstructs can achieve an emission rate of 1,000 lb CO
Highly efficient NGCC units include (1) an efficient combustion turbine engine, (2) an efficient steam cycle, and (3) a combustion turbine exhaust system that is “matched” to the steam cycle for maximum efficiency. In order for an existing NGCC unit to trigger the reconstruction provisions, the unit would have to essentially be entirely rebuilt. This would involve extensive upgrades to both the combustion turbine engine and the HRSG. Therefore, a reconstructed NGCC unit will be able to maximize the efficiency of the turbine engine and the steam cycle and match the two for maximum efficiency.
According to comments submitted in response to the proposal for existing sources under CAA section 111(d), there are various options available to improve the efficiency of existing combustion turbines. One combustion turbine manufacturer provided comments describing specific technology upgrades for the compressor, combustor, and gas turbine components. This manufacturer stated that operators of existing turbines can replace older internal components along the gas path with state-of-the-art components that have higher aerodynamic efficiencies and improved seal designs. These gas-path enhancements enable existing sources to both improve the efficiency of the turbine engine and improve the systems used for cooling the metal parts along the hot-gas path to allow existing systems to achieve higher operating temperatures. In total, the manufacturer stated that utilities deploying these gas-path improvements on reconstructed industrial frame combustion turbines with nominal output ratings of 170 to 180 MW can increase their output by 10 MW while reducing CO
In addition to upgrades to the combustion turbine engine, an operator reconstructing a NGCC unit will have the opportunity to improve the efficiency of the HRSG and steam cycle. For example, a steam turbine manufacturer identified three retrofit technologies available for reducing the CO
In addition, an operator reconstructing a NGCC unit could upgrade the entire steam cycle. For example, combined cycle units originally constructed with only a single pressure level can be upgraded to also include second and third pressure levels. Studies
Finally, we note that an owner or operator that is considering reconstructing an existing simple cycle turbine should decide how they wish to operate that turbine in the future. If they anticipate operating above the percentage electric sales threshold, then they should install a HRSG and steam turbine and convert to a NGCC power block in accordance with our determination that NGCC is the BSER for base load applications. If they intend to operate the turbine below the percentage electric sales threshold, however, then the clean fuels standard, described below, will apply.
The EPA agrees with the commenters who stated that “no emission limit” would be inconsistent with the requirements of CAA 111(a)(1). We therefore are finalizing an input-based standard based on the use of clean fuels for non-base load natural gas-fired combustion turbines in recognition that efficiency can be reduced due to operation at low loads, cycling, and frequent startups. The EPA has concluded that, at this time, we do not have sufficient information to set a meaningful output-based standard for non-base load natural gas-fired combustion turbines. The input-based standard requires non-base load units to burn fuels with an average emission rate of 120 lb CO
While the emission reductions that will result from restricting the use of fuels with higher CO
We also are finalizing an input-based standard based on the use of clean fuels, as opposed to an output-based standard, for multi-fuel units for several reasons. Specifically, we do not currently have continuous CO
The input-based emissions standard for this subcategory is based on the use of clean fuels. The use of clean fuels will ensure that newly constructed and reconstructed combustion turbines minimize CO
According to information submitted to the EIA, the primary, non-natural gas fuels used by combustion turbines today for the production of electricity should all meet our definition of a clean fuel. Thus, while the emission reductions that will result from restricting the use of fuels with higher CO
The EPA is not finalizing the proposed emission standards for stationary combustion turbines that conduct modifications. As explained in Section XV below, we are withdrawing the June 2014 proposal with respect to these sources. We received a significant number of comments asserting that modified combustion turbines could not meet the proposed emission standards of 1,000 lb/MWh-g for large turbines and 1,100 lb/MWh-g for small turbines. For the reasons explained in Section IX.B.1 above, we have decided not to subcategorize combustion turbines based on size for a number of reasons and are setting a single standard of
Combustion turbines have unique characteristics that make determining an appropriate emission standard for modified sources a more challenging task than for coal-fired boilers. For example, each combustion turbine engine has a specific corresponding combustor. The development of more efficient combustor upgrades for existing turbine designs typically requires manufacturers to expend considerable resources. Consequently, not all manufacturers offer combustor upgrades for smaller or older designs because it would be difficult to recoup their investment. In contrast, efficiency upgrades for boilers can generally be installed regardless of the specific boiler's characteristics.
In addition, natural gas has the lowest CO
To be clear, the EPA is not reaching a final decision that modifications should be subject to different requirements than we are finalizing in this rule for new and reconstructed sources. We have made no decisions, and this matter is not concluded. We plan to continue to gather information, consider the options for modifications, and develop a new proposal for modifications in the future. Therefore, the EPA is withdrawing the proposed standards for all combustion turbines that conduct modifications and is not issuing final standards for those sources at this time. See Section XV below. We note that the effect of this withdrawal is that modified combustion turbines will continue to be existing sources subject to section 111(d).
This section describes the final action's requirements regarding startup, shutdown, and malfunction; continuous monitoring; emissions performance testing; continuous compliance; and notification, recordkeeping, and reporting for newly constructed, modified, and reconstructed affected steam generating units and combustion turbines. We also explain final decisions regarding several of these requirements.
In its 2008 decision in
Consistent with
Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. Malfunctions, in contrast, are neither predictable nor routine. Instead they are, by definition sudden, infrequent and not reasonably preventable failures of emissions control, process or monitoring equipment. (40 CFR 60.2). The EPA interprets CAA section 111 as not requiring emissions that occur during periods of malfunction to be factored into development of section 111 standards. Nothing in CAA section 111 or in case law requires that the EPA consider malfunctions when determining what standards of performance reflect the degree of emission limitation achievable through “the application of the best system of emission reduction” that the EPA determines is adequately demonstrated. While the EPA accounts for variability in setting emissions standards, nothing in CAA section 111 requires the agency to consider malfunctions as part of that analysis. A malfunction should not be treated in the same manner as the type of variation in performance that occurs during routine operations of a source. A malfunction is a failure of the source to perform in a “normal or usual manner” and no statutory language compels the EPA to consider such events in setting CAA section 111 standards of performance.
Further, accounting for malfunctions in setting emission standards would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the
Given that compliance with the emission standard is determined on a 12-operating-month rolling average basis, the impact of periods of malfunctions on the total average over a 12-operating-month period is expected to be minimal. Thus, malfunctions over that period are not likely to result in a violation of the standard.
In the unlikely event that a source fails to comply with the applicable CAA section 111 standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failure to comply with the CAA section 111 standard was, in fact, sudden, infrequent, not reasonably preventable and was not instead caused in part by poor maintenance or careless operation. 40 CFR 60.2 (definition of malfunction).
If the EPA determines in a particular case that an enforcement action against a source for violation of an emission standard is warranted, the source can raise any and all defenses in that enforcement action and the federal district court will determine what, if any, relief is appropriate. The same is true for citizen enforcement actions. Similarly, the presiding officer in an administrative proceeding can consider any defense raised and determine whether administrative penalties are appropriate.
In summary, the EPA interpretation of the CAA and, in particular, CAA section 111 is reasonable and encourages practices that will avoid malfunctions. Administrative and judicial procedures for addressing exceedances of the standards fully recognize that violations may occur despite good faith efforts to comply and can accommodate those situations.
In the January 2014 proposal for newly constructed EGUs, the EPA had proposed to include an affirmative defense to civil penalties for violations caused by malfunctions in an effort to create a system that incorporates some flexibility, recognizing that there is a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission standards may be violated under circumstances entirely beyond the control of the source. Although the EPA recognized that its case-by-case enforcement discretion provides sufficient flexibility in these circumstances, it included the affirmative defense to provide a more formalized approach and more regulatory clarity. See
The majority of comments received on the proposal supported the EPA's use of existing monitoring requirements under the Acid Rain Program, which are contained in 40 CFR part 75 requirements. In response to this, the EPA is finalizing monitoring requirements that incorporate and reference the part 75 monitoring requirements for the majority of the CO
This final rule requires owners or operators of EGUs that combust solid fossil fuel to install, certify, maintain, and operate continuous emission monitoring systems (CEMS) to measure CO
The rule allows owners or operators of affected EGUs that burn exclusively gaseous or liquid fuels to install fuel flow meters as an alternative to CEMS and to calculate the hourly CO
In addition to requiring monitoring of the CO
The rule requires EGU owners or operators to prepare and submit a monitoring plan that includes both electronic and hard copy components, in accordance with 40 CFR 75.53(g) and (h). The electronic portion of the monitoring plan should be submitted to the EPA's CAMD using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. The hard copy portion of the plan should be sent to the applicable state and EPA Regional office. Further, all monitoring systems used to determine the CO
The rule requires all valid data collected and recorded by the monitoring systems (including data recorded during startup, shutdown, and malfunction) to be used in assessing compliance. Failure to collect and record required data is a violation of the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities that temporarily interrupt the measurement of stack emissions (
The rule requires only those operating hours in which valid data are collected and recorded for all of the parameters in the CO
This final rule includes the following special compliance provisions for units with common stack or multiple stack configurations; these provisions are consistent with 40 CFR 60.13(g):
• If two or more EGUs share a common exhaust stack, are subject to the same emission limit, and the operator is required to (or elects to) determine compliance using CEMS, then monitoring the hourly CO
• If the operator is required to (or elects to) determine compliance using CEMS and the effluent from the EGU discharges to the atmosphere through multiple stacks (or, if the effluent is fed to a stack through multiple ducts and is monitored in the ducts), then monitoring the hourly CO
The rule requires 95 percent of the operating hours in each compliance period (including the compliance periods for the intermediate emission limits) to be valid hours,
Similarly to the comments received on monitoring for the proposal, commenters in general supported the use of current testing requirements required under the Acid Rain Program 40 CFR part 75 requirements. Thus the EPA is finalizing requirements for performance testing as consistent with part 75 requirements where appropriate to ensure the quality and accuracy of data and measurements as required by the final rule.
In accordance with 40 CFR 75.64(a), the final rule requires an EGU owner or operator to begin reporting emissions data when monitoring system certification is completed or when the 180-day window in 40 CFR 75.4(b) allotted for initial certification of the monitoring systems expires (whichever date is earlier). For EGUs subject to the
The traditional 3-run performance tests (
Commenters supported the use of a 12-operating-month rolling average for the compliance period for the final standards. In response, this final rule specifies that compliance with the 1,400 lb CO
The rule specifies that the first operating month included in the initial 12-operating-month compliance period is the month in which reporting of emissions data is required to begin under 40 CFR 75.64(a),
Initial compliance with the applicable emissions limit in kg/MWh is calculated by dividing the sum of the hourly CO
Several commenters stated that the final rule should require operators to round their calculated emissions rates to three significant figures when comparing their actual rates to the standard. These commenters said that allowing use of only two significant digits when calculating the 12-operating-month rolling average emission rate would constitute relaxation of the standard by 5 percent because an actual emission rate of 1,049.9 lb CO
The General Provisions of Part 60 specify the rounding conventions for compliance calculations at 40 CFR 60.13(h)(3) including the provision that “after conversion into units of the standard, the data may be rounded to the same number of significant digits used in the applicable subpart to specify the emission limit.”
The final rule requires that the 12-operating-month rolling average emission rate must be rounded to three significant figures if the applicable emissions standard is greater than or equal to 1,000 (
The final rule requires rounding of emission rates with numerical values greater than or equal to 1,000 to three significant figures and rounding of rates with numerical values less than 1,000 to two significant figures.
Commenters supported the coordination of notification, recordkeeping, and reporting required under this rule in conjunction with the requirements already in place under part 75, so the EPA has made the requirements as efficient and streamlined as possible with the current requirements under part 75. The final rule requires an EGU owner or operator to comply with the applicable notification requirements in 40 CFR 75.61, 40 CFR 60.7(a)(1) and (a)(3), and 40 CFR 60.19. The rule also requires the applicable recordkeeping requirements in subpart F of part 75 to be met. For EGUs using CEMS, the data elements that are recorded include, among others, hourly CO
The rule requires EGU owners or operators to keep records of the calculations they perform to determine the total CO
Sources are required to keep all records for a period of 3 years. All required records must be kept on-site for a minimum of two years, after which the records can be maintained off-site.
The rule requires all affected EGU owners/operators to submit quarterly electronic emissions reports in accordance with subpart G of part 75. The reports in appendix G that do not include data required to calculate compliance with the applicable CO
Additionally, in the final rule and as part of an agency-wide effort to streamline and facilitate the reporting of environmental data, the rule requires selected data elements that pertain to compliance under this rule, and that serve the purpose of identifying violations of an emission standard, to be reported periodically using ECMPS.
Specifically, EGU owners/operators must submit quarterly electronic reports within 30 days after the end of each quarter consistent with current part 75 reporting requirements. The first report is for the quarter that includes the final (12th) operating month of the initial 12-operating-month compliance period. For that initial report and any subsequent report in which the 12th operating month of a compliance period (or periods) occurs during the calendar quarter, the average CO
Currently, ECMPS is not programmed to receive the additional information included in the report required under 40 CFR 60.5555(a)(2) for affected EGUs. However, we will make the necessary modifications to the system in order to fully implement the reporting requirements of this rule upon promulgation.
In the CAA section 111(d) rule for existing steam units and combustion turbines that the EPA is promulgating at the same time as this CAA section 111(b) rule, the EPA is identifying as part of the BSER for those sources, building block 1 (for steam units, efficient operation), building block 2 (for steam units, dispatch shift to existing NGCC units), and building block 3 (for steam units and combustion turbines, substitution of generation with new renewable energy). In this section, we explain why the EPA is not identifying building blocks 1, 2, or 3 as part of the BSER for new, modified, or reconstructed steam generators or combustion turbines.
As discussed in this preamble and in more detail in the preamble to the CAA section 111(d) rule for existing sources, the phrase “system of emission reduction” is undefined and provides the EPA with discretion in setting a standard of performance under CAA section 111(b) or emission guidelines under CAA section 111(d). Because the phrase by its plain language does not limit our review of potential systems in either context, the same systems could be considered for application in new and existing sources. That said, many other factors and considerations direct us to focus on different systems when establishing a standard of performance under CAA section 111(b) and an emission guideline under CAA section 111(d). Thus, it is useful to describe part of the underlying basis for the BSER—partial CCS—that the EPA has determined for new steam units before discussing the building blocks that form the BSER for existing units.
For new steam generating units, the EPA is identifying, as the BSER, systems of emission reduction that assure that these sources are inherently low-emitting at the time of construction. The following reasons support this approach to the BSER.
New sources are expected to have long operating lives over which initial capital costs can be amortized. Thus, new construction is the preferred time to drive capital investment in emission controls. In this case, the BSER for new steam generators, partial CCS, requires substantial capital expenditures, which new sources are best able to accommodate.
While CAA section 111(b)(1)(B) and (a)(1) by their terms do not mandate that the BSER assure that new sources are inherently low emitting, that approach to the BSER is consistent with the legislative history.
Several practical considerations make the building blocks inappropriate for new sources. Thus, for the following reasons, the EPA does not consider it appropriate to include the building blocks as part of the BSER for new sources:
Partial CCS will impose substantial (albeit reasonable) costs on new steam-generating EGUs, and, as a result, the EPA does not believe that including additional measures as part of the BSER would be appropriate. One disadvantage in adding additional costs is that doing so would make it more difficult for new steam-generating EGUs to compete with new nuclear units. Because the BSER is selected after considering cost (among other factors), the EPA is not required to,
Building block 1 measures are not appropriate (or would be redundant) because the BSER for new steam generating units is based on highly efficient supercritical technology,
Building block 2 and 3 measures are not appropriate for the BSER because new steam units would have a significantly limited range of options to implement building blocks 2 and 3. The new source performance standard was proposed and is being finalized as a rate-based standard. Thus, if building blocks 2 and 3 were included in the BSER, a more stringent rate-based standard would be applicable to all new sources. However, it is conceivable that the EPA could propose a hybrid standard that would include both an emission-rate limit that reflects partial CCS and a requirement for allowances that reflects building blocks 2 and 3. Accordingly, the following discussion assumes either a rate-based or mass-based standard, or part of a hybrid standard.
In both a rate-based program and a mass-based program, building blocks 2 and 3 measures can be implemented through a range of methods, including trading with other EGUs. While it is not necessarily the case that every existing source will be able to implement each of the methods, in general, existing sources will have a range of measures to choose from. However, at least some of those methods may not be available to new sources, which would render compliance with their emission limits more challenging and potentially more costly.
One example is emission trading with other affected EGUs. For existing sources, emission trading is an important option for implementing the building blocks. There are large numbers of existing sources, and they will become subject to the section 111(d) standards of performance at the same time. It may be more cost-effective for some to implement the building blocks than others, and, as a result, some may over-comply and some may under-comply, and the two groups may trade with each other. Because of the large numbers of existing sources, the trading market can be expected to be robust. Trading optimizes efficiency. As a result, existing sources have more flexibility in the overall amount of their investment in building blocks 2 and 3 and can adjust investment obligations among themselves through emissions trading.
In contrast, new sources construct one at a time, and it is unknown how many new sources there will be. Without a sizeable number of new sources, there will not be a robust trading market. Thus, a new source cannot count on being able to find a new source trading partner. In addition, it is not possible to count on new sources being able to trade with existing sources, for several reasons. First, as noted, there are indications in the legislative history that new sources should be well-controlled at the source, which casts doubt on whether new sources should be allowed to meet their standards through the purchase of emission credits. Second, new sources must meet their standards of performance as soon as they begin operations. If they do so before the year 2022, when existing sources become subject to section 111(d) state plan standards of performance, no existing sources will be available as trading partners.
In addition, for section 111(d) sources, we are granting a 7-year period of lead-time for the implementation of the building blocks. This is due, in part, to the benefits of allowing the ERC and allowance markets to develop. However, the new source standards take effect immediately, so new sources would not have the advantage of this lead time were they subject to more stringent standards that also reflected the building blocks.
In addition, if there are an unexpectedly large number of new sources, then they would be obliged to invest in greater amounts of building blocks 2 and 3, and that could reduce the amounts of building blocks 2 and 3 available for existing sources, and thereby raise the costs of building blocks 2 and 3 for existing sources. This could compromise the BSER under section 111(d) and undermine the ability of existing sources to comply with their section 111(d) obligations.
For new combustion turbines, the building blocks are not appropriate as part of the BSER either. Building block 1 is limited to steam generating units, and therefore has no applicability to new combustion turbines. Measures comparable to those in building block 1 would not be appropriate because new highly efficient NGCC construction already entails high efficiency equipment and operation. Building block 2 is also limited to steam generating units and is not appropriate as part of the BSER for new NGCC units because it would not result in any emission reductions.
The reasons why building block 3 are not appropriate are the same as discussed above for why building blocks 2 and 3 are not appropriate for new steam generating units (limited range of options for implementation (including lack of availability of trading), lack of
For modified and reconstructed steam generators, the EPA identified the BSER as maintenance of high efficiency or implementation of a highly efficient unit. The resulting emission limit must be met over the specified time period and cannot be deviated from or averaged. As a result, a modified or reconstructed steam generator generally will require ongoing maintenance and may find it prudent to operate below its limit as a safety margin. This represents a substantial commitment of resources. For these units, the additional costs of implementing the building blocks would not be appropriate.
In addition, building block 1 is not appropriate for modified or reconstructed steam generating units because the BSER for these units is already based on highly efficient performance. For the same reasons, it does not make sense to attempt to develop the analogue to building block 1 for reconstructed NGCC units—the BSER for them, too, is already based on highly efficient performance.
Building block 2 is not appropriate for reconstructed NGCC units because it would not yield any reductions.
Building blocks 2 and 3 are not appropriate for modified or reconstructed steam generators, and building block 3 is not appropriate for reconstructed NGCC units, for the same reasons that they are not appropriate for new EGUs, as described above (limited range of options for implementation (including lack of availability of trading), lack of lead-time for implementation, and the possibility of reducing the availability of renewable energy for existing sources).
This final rule will, for the first time, regulate GHGs under CAA section 111. In Section IX of the preamble to the proposed rule, the EPA addressed how regulation of GHGs under CAA section 111 could have implications for other EPA rules and for permits written under the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA Title V operating permit program. The EPA proposed to adopt provisions in the regulations that explicitly addressed some of these implications.
For purpose of the PSD program, the EPA is finalizing provisions in part 60 of its regulations that make clear that the threshold for determining whether a PSD source must satisfy the BACT requirement for GHGs continues to apply after promulgation of this rule. This rule does not require any additional revisions to State Implementation Plans. As discussed further below, this final rule may have bearing on the determination of BACT for new, modified, and reconstructed EGUs that require PSD permits. With respect to the Title V operating permits program, this rule does not affect whether sources are subject to the requirement to obtain a Title V operating permit based solely on emitting or having the potential to emit GHGs above major source thresholds. However, this rule does have some implications for Title V fees, which the EPA is addressing in this final rule.
Finally, the fossil fuel-fired EGUs covered in this rule are or will be potentially impacted by several other recently finalized or proposed EPA rules, and such potential interactions with other EPA rules are discussed below.
In our January 8, 2014 proposal, the EPA proposed to adopt regulatory language in 40 CFR part 60 that would ensure the promulgation of this NSPS would not undercut the application of rules that limit the application of the PSD permitting program requirements to only the largest sources of GHGs. An intervening decision of the United States Supreme Court has, to a large extent, resolved the legal issue that led the EPA to propose these part 60 provisions. The Supreme Court has since clarified that the PSD program does not apply to smaller sources based on the amount of GHGs they emit. However, because the largest sources emitting GHGs remain subject to the PSD permitting requirements, the EPA has concluded that it remains appropriate to adopt the proposed regulatory provisions in 40 CFR part 60 in this rule. We discuss our reasons for this action in detail below.
Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is required to obtain a preconstruction permit. This permit assures that the source meets specific requirements, including application of BACT to each pollutant subject to regulation under the CAA. Many states (and local districts) are authorized by the EPA to administer the PSD program and to issue PSD permits. If a state is not authorized, then the EPA issues the PSD permits for facilities in that state.
To identify the pollutants subject to the PSD permitting program, EPA regulations contain a definition of the term “regulated NSR pollutant.” 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition contains four subparts, which cover pollutants regulated under various parts of the CAA. The second subpart covers pollutants regulated under section 111 of the CAA. The fourth subpart is a catch-all provision that applies to “[a]ny pollutant that is otherwise subjection to regulation under the Act.”
This definition and the associated PSD permitting requirements applied to GHGs for the first time on January 2, 2011, by virtue of the EPA's regulation of GHG emissions from motor vehicles, which first took effect on that same date. 75 FR 17004 (Apr. 2, 2010). As such, GHGs became subject to regulation under the CAA and the fourth subpart of the “regulated NSR pollutant” definition became applicable to GHGs.
On June 3, 2010, the EPA issued a final rule, known as the Tailoring Rule, which phased in permitting requirements for GHG emissions from stationary sources under the CAA PSD and Title V permitting programs (75 FR 31514). Under its understanding of the CAA at the time, the EPA believed the Tailoring Rule was necessary to avoid a sudden and unmanageable increase in the number of sources that would be required to obtain PSD and Title V permits under the CAA because the sources emitted GHGs emissions over applicable major source and major modification thresholds. In Step 1 of the Tailoring Rule, which began on January 2, 2011, the EPA limited application of PSD or Title V requirements to sources of GHG emissions only if the sources were subject to PSD or Title V “anyway” due to their emissions of non-GHG pollutants. These sources are referred to as “anyway sources.” In Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA applied the PSD and Title V permitting requirements under the CAA to sources that were classified as major, and, thus, required to obtain a permit, based solely on their potential GHG emissions and to modifications of otherwise major sources that required a PSD permit because they increased only GHG emissions above applicable levels in the EPA regulations.
In the PSD program, the EPA implemented the steps of the Tailoring Rule by adopting a definition of the
This structure of the EPA's PSD regulations created questions regarding the extent to which the limitations in the Tailoring Rule would continue to apply to GHGs once they became regulated, through this final rule, under section 111 of the CAA. 79 FR 1487-1488. As discussed above, the definition of “regulated NSR pollutant” in the PSD regulations contains a separate PSD trigger for air pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the “NSPS trigger provision”). Thus, when GHGs become subject to a standard promulgated under CAA section 111 for the first time under this rule, PSD requirements would presumably apply for GHGs on an additional basis besides through the regulation of GHGs from motor vehicles. However, the Tailoring Rule, on the face of its regulatory provisions, incorporated the revised thresholds it promulgated into only the fourth subpart of the PSD definition of regulated NSR pollutant (“[a]ny pollutant that otherwise is subject to regulation under the Act”). The regulatory text does not clearly incorporate the thresholds into the NSPS trigger provision in the second subpart (“[a]ny pollutant that is subject to any standard promulgated under section 111 of the Act”). For this reason, a question arose as to whether the Tailoring Rule limitations would continue to apply to the PSD requirements after they are independently triggered for GHGs by the NSPS that the EPA is now promulgating. Stakeholders questioned whether the EPA must revise its PSD regulations —and, by the same token, whether states must revise their SIPs—to assure that the Tailoring Rule thresholds will continue to apply to sources potentially subject to PSD under the CAA based on GHG emissions.
In the January 8, 2014 proposed rule, the EPA explained that the agency had included an interpretation in the Tailoring Rule preamble, which means that the Tailoring Rule thresholds continue to apply if and when the EPA promulgates requirements under CAA section 111. 79 FR 1488 (citing 75 FR 31582). Nevertheless, to ensure there would be no uncertainty as to this issue, the EPA proposed to adopt explicit language in 40 CFR 60.46Da(j), 40 CFR 60.4315(b), and 40 CFR 60.5515 of the agency's regulations. The proposed language makes clear that the thresholds for GHGs in the EPA's PSD definition of “subject to regulation” apply through the second subpart of the definition of “regulated NSR pollutant” to GHGs regulated under this rule.
The EPA received comments supporting the adoption of this proposed language, but several commenters also expressed concern that adding this language to part 60 alone would not be sufficient. Several commenters urged the EPA to instead revise the PSD regulations in parts 51 and 52. In addition, commenters expressed concern that further steps were needed to amend the SIPs before there would be certainty that the Tailoring Rule limitations continued to apply after the adoption of CO
On June 23, 2014, the United States Supreme Court, in
In accordance with the Supreme Court decision, on April 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) issued an amended judgment vacating the regulations that implemented Step 2 of the Tailoring Rule, but not the regulations that implement Step 1 of the Tailoring Rule. The court specifically vacated 40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA's regulations, but did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR 52.21(b)(48)(iv). The court also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of
The practical effect of the Supreme Court's clarification of the reach of the CAA is that it eliminates the need for Step 2 of the Tailoring Rule and subsequent steps of the GHG permitting phase in that the EPA had planned to consider under the Tailoring Rule. This also eliminates the possibility that the promulgation of GHG standards under section 111 could result in additional sources becoming subject to PSD based solely on GHGs, notwithstanding the limitations the EPA adopted in the Tailoring Rule. However, for an interim period, the EPA and the states will need to continue applying parts of the PSD definition of “subject to regulation” to ensure that sources obtain PSD permits meeting the requirements of the CAA.
The CAA continues to require that PSD permits issued to “anyway sources” satisfy the BACT requirement for GHGs. Based on the language that remains applicable under 40 CFR 51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv), the EPA and states may continue to limit the application of BACT to GHG emissions in those circumstances where a source emits GHGs in the amount of at least 75,000 tpy on a CO
While the PSD rulemaking described above is pending, the EPA and approved state, local, and tribal permitting authorities will still need to implement the BACT requirement for GHGs. In order to enable permitting authorities to continue applying the 75,000 tpy CO
The EPA has evaluated 40 CFR 60.5515 in light of the Supreme Court decision and the comments received on the question of whether this CAA section 111 standard will undermine the application of the Tailoring Rule limitations. While most of the Tailoring Rule limitations are no longer needed to avoid triggering the requirement to obtain a PSD permit based on GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv) will remain important to provide an interim applicability level for the GHG BACT requirement in “anyway source” PSD permits. Thus, there continues to be a need to ensure that the regulation of GHGs under CAA section 111 does not make this BACT applicability level for anyway sources effectively inoperable. The language in 40 CFR 60.5515 will continue to be effective at avoiding this result after the judicial actions described above and the adoption of this final rule. The provisions in part 60 reference 40 CFR 51.166(b)(48) and 40 CFR 52.21(b)(49) of the EPA's regulations. However, the courts have now vacated 40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v), and the EPA will take steps soon to eliminate these subparts from the CFR. As a result of these steps, the language of final 40 CFR 60.5515 will not incorporate the vacated parts of 40 CFR 51.166(b)(48) and 40 CFR 52.21(b)(49), but these provisions in part 60 will continue to apply to those subparts of the PSD rules that are needed on an interim basis to limit application of BACT to GHGs only when emitted by an anyway source in amounts of 75,000 tpy CO
As to the concern expressed by some commenters that revisions to part 60 alone are not sufficient, the GHG SER rulemaking described above will include proposed revisions to the PSD regulations in parts 51 and 52 that should ultimately address this concern. The EPA acknowledges that the commenters concern will not be fully addressed for an interim period of time, but (for the reasons discussed above) the part 60 provisions adopted in this rule are sufficient to make explicit that the 75,000 tpy CO
Rather than adopting a temporary patch in its PSD regulations in this rule to address the implications for PSD of regulating GHGs under CAA section 111, the EPA believes it will be most efficient for the EPA and the states if the EPA completes a comprehensive PSD rule that will address all the implications of the Supreme Court decision. The revisions the EPA will consider based on the Supreme Court decision will inherently address the commenters concerns about the definition of the “subject to regulation” and the proposed part 60 provisions. To the extent this PSD rule is not complete before the EPA proposes additional CAA section 111 standards for GHGs, the EPA will need to consider adding provisions like 40 CFR 60.5515 to other subparts of part 60. In a separate rulemaking finalized concurrently with this rule, the EPA is also finalizing corresponding edits to 40 CFR 60.5705 in subpart UUUU to clarify that the regulated pollutant is the same for both the CAA section 111(b) and section 111(d) rules. As of this time, the EPA has not proposed GHG standards for other source categories under CAA section 111. To the extent needed, this approach of adding provisions to a few subparts in part 60 would be less burdensome to states and more efficient than revising 40 CFR 51.166 at this time solely to address the implications of regulating GHGs under CAA section 111.
The EPA understands that many commenters expressed concern that PSD SIPs would also have to be amended to address the implications of regulating GHGs under CAA section 111. However, the language in 40 CFR 60.5515 is designed to avoid the need for states to make revisions to the PSD regulations in their SIPs at this time. The EPA has previously observed that the form of each pollutant regulated under the PSD program is derived from the form of the pollutant described in regulations, such as an NSPS, that make the pollutant regulated under the CAA. 56 FR 24468, 24470 (May 30, 1991); 61 FR 9905, 9912-18 (Mar. 12, 1996); 75 FR 31522.
Moreover, it is more likely that states would need to consider a SIP revision if the EPA were to revise 40 CFR 51.166 in this rule. Revisions to 51.166 can trigger requirements for states to revise their PSD program provisions under 40 CFR 51.166(a)(6).
Given the process required in states to review their SIPs and submit them to the EPA for approval, it is most efficient for all concerned when the EPA is able to consolidate its revisions to 40 CFR 51.166. The EPA, thus, believes it will be less work for states if we issue a comprehensive set of rules addressing regulation of GHGs under the PSD program after the Supreme Court decision.
In comments on the proposed rules, states generally did not express concern that the proposed revisions to part 60 were insufficient to avoid the need for SIP revisions. In our proposal, we addressed any state with an approved PSD SIP program that applies to GHGs which believed that this final rule would require the state to revise its SIP so that the Tailoring Rule thresholds continue to apply. First, the EPA encouraged any state that considered such revisions necessary to make them as soon as possible. Second, if the state could do so promptly, the EPA said it would assess whether to proceed with a separate rulemaking action to narrow its approval of that state's SIP so as to assure that, for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date of the final NSPS rule. 79 FR 1487. The EPA did not receive any comments or other feedback from states requesting that the EPA narrow their program to ensure the Tailoring Rule thresholds continue to apply after promulgating this rule. We do not believe such action will be necessary in any state after the Supreme Court decision and our action in this rule is to adopt the proposed part 60 provisions for purposes of ensuring the Step 1 BACT applicability level for GHGs continues to apply on an interim basis.
New major stationary sources and major modifications at existing major stationary sources are required by the
Sources that are subject to PSD must obtain a preconstruction permit that contains emission limitations based on application of BACT for each regulated NSR pollutant. The BACT requirement is set forth in section 165(a)(4) of the CAA, and in EPA regulations under 40 CFR parts 51 and 52. These provisions require that BACT determinations be made on a case-by-case basis. CAA section 169(3) defines BACT, in general, as:
BACT is a case-by-case review that considers a number of factors. These factors include the availability, technical feasibility, control effectiveness, and the economic, environmental and energy impacts of the control option. See GHG Permitting Guidance at 17-46. The fact that a minimum control requirement (
It is important to understand how this NSPS may relate to determining BACT for new and existing EGUs that require PSD permits. PSD generally applies to major sources, while this NSPS applies to units that may be within a source. Under this NSPS, an affected facility is a new EGU or a modified or reconstructed EGU. The new source NSPS requirements apply, in general, to any stationary source that adds a new EGU that is an affected facility under this NSPS. This could, for example, include a proposed brand new (“greenfield”) power plant or an existing power plant that proposes to add a new EGU (
In addition, this NSPS will apply to some modified and reconstructed units, as those terms are defined under part 60. Consequently, this NSPS could establish a BACT floor for existing stationary sources that are modifying an existing EGU and experience an emissions increase that makes the source subject to PSD review. However, a physical change that triggers the NSPS modification or reconstruction requirements does not necessarily subject the source to PSD requirements, and vice versa. In general, in order to trigger the NSPS modification or reconstruction requirements, a physical change must increase the maximum hourly emission rate of the pollutant (to be an NSPS modification) or the fixed capital cost of the change must exceed 50 percent of the fixed capital cost of a comparable entirely new facility (to be an NSPS reconstruction).
In the preamble to the proposed NSPS for new sources, the EPA discussed whether a standard of performance for the new source NSPS, specifically the BSER for solid fuel-fired EGUs that is based on partial CCS, could become the BACT floor when permitting a modified or reconstructed EGU or non-EGU source. As noted above, BACT is a case-specific review by a permitting agency. In evaluating BACT, the permitting authority should consider all available control technologies that have the potential for practical application to the facility or emission unit under evaluation. See GHG Permitting Guidance at 24. This BACT review must include any technologies that are part of an applicable NSPS for the specific type of source and would therefore establish the minimum level of stringency for the BACT. Thus, it is possible that partial CCS could be considered in a BACT review as an available control option for a modified or reconstructed EGU facility, or for another type of source (
Some commenters expressed concern that, if the EPA finalizes a BSER for utility boilers and IGCC units that is based on partial CCS, it would establish a BACT Floor for new EGUs that would be inconsistent with prior BACT determinations for EGUs in both permits issued by EPA Regions and permits issued by state agencies on which the EPA has commented. Many of these comments were more directed at the development and deployment of CCS (
With regard to the commenters who stated that a BSER for EGUs that is based on partial CCS would be inconsistent with BACT determinations in previous GHG PSD permits, it is important to recognize that a BACT determination is a case-by-case analysis and that technological capabilities and costs evolve over time.
As explained at Section V.I.5 above, in determining that partial CCS is BSER for new fossil fuel steam electric plants, the EPA has carefully considered the issue of logistics (including cost estimates for land acquisition, transportation, and sequestration) and costs generally. Nor would new plants face the same types of constraints as modified or reconstructed sources in a BACT determination, since a new source has more leeway in choosing where to site. See text at V.G.3. above. Moreover, the GHG Permitting Guidance considered BACT determinations for all types of sources, not just those for which the EPA has determined in this rule that partial CCS is the BSER, and the concerns expressed in the Guidance thus must be considered in that broader context.
Additionally, if a state agency is processing a permit application for a solid fuel-fired EGU and does not propose CCS as BACT (or does not even consider CCS as an available control for BACT), the EPA is not necessarily required to comment negatively on the draft permit, or to otherwise request or require that the state agency amend the BACT to include CCS. For state agencies that have their own EPA-approved state implementation plan, the state has primacy over their permitting actions and discretion to interpret their approved rules and to apply the applicable federal and state regulatory requirements that are in place at the time for the facility in question. The EPA's role is to provide oversight to ensure that the state operates their PSD program in accordance with the CAA and applicable rules. If the EPA does not adversely comment on a certain draft permit or BACT determination, it does not necessarily imply EPA endorsement of the proposed permit or determination.
Some commenters also felt that the determination of partial CCS as BSER is inconsistent with the agency's position on CCS in the EPA's GHG Permitting Guidance, which they say supports the notion that additional work is required before CCS can be integrated at full-scale electric utility applications. It is important to recognize that the EPA's Permitting Guidance is guidance, so it does not contain any final determination of BACT for any source. Furthermore, we disagree with the commenters' characterization of the GHG Permitting Guidance. The Guidance specifically states “[f]or the purposes of a BACT analysis for GHGs, the EPA classifies CCS as an add-on pollution control technology that is “available” for facilities emitting CO
The GHG Permitting Guidance continues on to discuss case-specific factors and potential limitations with applying CCS, and it acknowledges that CCS may not be ultimately selected as BACT in “certain cases” based on technology feasibility and cost. GHG Permitting Guidance at 36, 43. While acknowledging these potential challenges when it was issued in March 2011, the Guidance clearly does not rule out the selection of CCS as BACT for any source category and it is forward looking. GHG Permitting Guidance at 43 (“. . . as a result of ongoing research and development, . . . CCS may become less costly and warrant greater consideration . . . in the future”) Nothing in the Guidance is inconsistent with EPA's present position that CCS is adequately demonstrated for the types of sources covered by this NSPS, as articulated elsewhere in this preamble.
A commenter asserted that the GHG Permitting Guidance should be amended because it calls for consideration of CCS in BACT determinations even though the proposed NSPS identified “partial CCS” as BSER for new boiler and IGCC EGUs. The Guidance explains that “the purpose of Step 1 of the process is to cast a wide net and identify all control options with potential application to the emissions unit under review.” GHG Permitting Guidance at 26. The EPA agrees that the GHG Permitting Guidance only uses the term “CCS” and does not distinguish “partial CCS” from “full CCS.” But considering the purpose of Step 1 of the process, we believe that the term “CCS”, as it is used in the GHG Permitting Guidance, adequately describes the varying levels of CO
Under the Title V program, certain stationary sources, including “major sources” are required to obtain an operating permit. This permit includes all of the CAA requirements applicable to the source, including adequate monitoring, recordkeeping, and reporting requirements to assure sources' compliance. These permits are generally issued through EPA-approved state Title V programs.
In the January 8, 2014 proposal, the EPA discussed whether this rulemaking would impact the applicability of Title V requirements to major sources of GHGs. 79 FR 1489-90. The relevant issue for Title V purposes was, in essence, whether promulgation of CAA section 111 requirements for GHGs
As noted elsewhere in this section, after the proposal for this rulemaking was published, the United States Supreme Court issued its opinion in
With respect to Title V, the Supreme Court said in
To be clear, however, unless exempted by the Administrator through regulation under CAA section 502(a), any source, including an area source (a “non-major source”), subject to an NSPS is required to apply for, and operate pursuant to, a Title V permit that assures compliance with all applicable CAA requirements for the source, including any GHG-related applicable requirements. This aspect of the Title V program is not affected by
The January 8, 2014 notice of proposed rulemaking (79 FR 1430) (the “EGU GHG NSPS proposal” or “NSPS proposal”) proposed the first section 111 standards to regulate GHGs at EGUs. That notice also included proposed revisions to the fee requirements of the 40 CFR part 70 and part 71 operating permit rules under Title V of the CAA to avoid inadvertent consequences for fees that would be triggered by the promulgation of the first CAA section 111 standard to regulate GHGs. If we do not revise the fee rules by the time of the promulgation of the NSPS standards for GHGs, then approved part 70 programs implemented by state, local and tribal permitting authorities
In response to these concerns, the EPA proposed regulatory changes to limit the fees collected based on GHG emissions and proposed two fee adjustment options to increase the fees collected based on the costs for permitting authorities to conduct certain review activities related to GHG emissions, while still providing sufficient funding for an operating permit program. Also, we proposed an option that would have provided for no fee adjustments to recover the costs of conducting review activities related to GHG emissions.
Most commenters on the proposal, including state and local permitting authorities, were supportive of exempting GHGs from the emissions-based fee calculations of the permit
In the NSPS proposal, the EPA explained the statutory and regulatory background related to the requirement that permitting authorities collect fees from the owner or operator of Title V sources that are sufficient to cover the costs of the operating permit program. CAA section 502(b)(3)(A) requires an operating permit program to include a requirement that sources “pay an annual fee, or the equivalent over some other period, sufficient to cover all reasonable (direct and indirect) costs required to develop and administer the permit program.” See also 40 CFR 70.9(a). CAA section 502(b)(3)(B)(i) requires that, in order to have an approvable operating permit program, the permitting authority must show that “the program will result in the collection, in the aggregate, from all sources [required to get an operating permit]” of either “an amount not less than $25 per ton of each regulated pollutant [adjusted annually for changes in the consumer price index], or such other amount as the Administrator may determine adequately reflects the reasonable costs of the permit program.” See also 40 CFR 70.9(b)(2). This has been generally referred to as the “presumptive minimum” approach. If a permitting authority does not wish to use the presumptive minimum approach, it may demonstrate “that collecting an amount less than the [presumptive minimum amount] will” result in the collection of funds sufficient to cover the costs of the program. CAA section 503(b)(3)(B)(iv); see also 40 CFR 70.9(b)(5). This has been generally referred to as the “detailed accounting” approach. CAA section 502(b)(3)(B)(ii) sets forth a definition of “regulated pollutant” for purposes of calculating the presumptive minimum that includes each pollutant regulated under section 111 of the CAA. See also 40 CFR 70.2.
In the NSPS proposal, to exempt GHGs from emissions-based fee calculations, we proposed to exempt GHGs from the definition of “regulated pollutant” for purposes of operating permit fee calculations (“the GHG exemption”). The EPA then proposed two alternative ways to account for the costs of addressing GHGs in operating permits through a cost adjustment. First, we proposed a modest additional cost for each GHG-related activity of certain types that a permitting authority would process (“the GHG adjustment option 1”). Alternatively, we proposed a modest additional increase in the per ton rate used in the presumptive minimum calculation for all non-GHG fee pollutants (“the GHG adjustment option 2”). The EPA also solicited comment on an option that would provide no additional cost adjustment to account for GHGs (“the GHG adjustment option 3”). All of the GHG adjustment options are based on the assumption that the GHG exemption is finalized. See NSPS Proposal 79 FR 1493-1495.
The EPA additionally proposed two clarifications. The first was regulatory text in 40 CFR part 60, subparts Da, KKKK, and TTTT, to clarify that GHGs, as opposed to CO
For background purposes, below is a brief summary of each of the proposals.
To address the fee issues discussed in the NSPS proposal, the EPA proposed to exempt GHG emissions from the definition of “regulated pollutant (for presumptive fee calculation)” in 40 CFR 70.2 and the definition of “regulated pollutant (for fee calculation)” in 40 CFR 71.2.
The first proposed “GHG adjustment” option (option 1) was to include an additional cost for each GHG-related activity of certain types that a permitting authority would process (an activity-based adjustment). The three activities identified for this option were “GHG completeness determination (for initial permit or for updated application)” at 43 hours of burden,
For part 70, the burden hours per activity would be multiplied by the cost of staff time (in $/hour) specific to the state, including wages, benefits, and overhead, to determine the cost of each activity. All the activities for a given period would be totaled to determine the total GHG adjustment for the state. See 79 FR 1494.
For part 71, we proposed a labor rate assumption of $52 per hour in 2011 dollars. Using that labor rate, we proposed to determine the GHG fee adjustment for each GHG permitting program activity to be a specific dollar amount for each activity (“set fees”) that the source would pay for each activity performed. See 79 FR 1495. The EPA proposed to revise 40 CFR 70.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement this option.
The second proposed GHG adjustment option (option 2) was to increase the dollar per ton ($/ton) rates used in the fee calculations for each non-GHG fee pollutant. The revised $/ton rates would be multiplied by the total tons of non-GHG fee pollutants actually emitted by any source to determine the applicable total fees. The EPA proposed to increase the $/ton rates by 7 percent.
The EPA also solicited comment on not charging any fees related to GHGs (option 3). The basis for this proposed option was the observation that most sources that need to address GHGs in a permit would also emit non-GHG fee pollutants, and thus, the cost of permitting for any particular source may be accounted for adequately without charging any additional fees related to GHGs.
Another fee-related proposal was to add regulatory text to 40 CFR part 60, subparts Da, KKKK, and TTTT, to clarify that the fee pollutant for operating permit purposes would be considered to be “GHGs,” (as defined in
The EPA proposed to move the existing definition of “Greenhouse gases (GHGs)” within the definition of “Subject to regulation” in 40 CFR 70.2 and 71.2 to a separate definition within those sections to promote clarity in the regulations.
In this action, the EPA is finalizing the following elements as proposed: (1) The GHG exemption, (2) the GHG adjustment option 1, and (3) the fee pollutant clarification.
Public commenters on the proposal stated both support and opposition to using the NSPS rulemaking action to revise the Title V fee rules. Two commenters stated that proposing the Title V fee revisions within the NSPS rulemaking would result in fewer commenters, particularly state and local permitting authorities, having knowledge of the changes to the fee rules and sufficient opportunity to comment on the changes because the NSPS proposal is limited to a single source category, and one stated that a separate proposal for the fee rules would provide a sufficient opportunity for public comment. The EPA believes it is appropriate to move forward with final action amending the Title V fee regulations as part of this NSPS. As we explained in the preamble for the proposal and elsewhere in this final rule, the fee rules and the section 111 standards are interrelated because, if we do not revise the fee rules, promulgation of the final NSPS will trigger certain requirements related to Title V fees for GHG emissions that the EPA believes will result in the collection of excessive fees in states that implement the presumptive minimum approach and in the part 71 program. Thus, it is important to finalize the revisions to the fee rules at the same time or prior to this NSPS, and it is within the EPA's discretion to address the NSPS and the fee rules at the same time as part of the same rulemaking action. In response to the commenters who were concerned that including the fee rule proposal as part of the NSPS proposal would result in the public not having sufficient public comment opportunities, the EPA believes sufficient public comment opportunities were provided on the fee rule changes because the proposal met all public participation requirements and we provided additional public outreach, including to state and local permitting authorities, which discussed the fee rule proposal. In addition to the publication of the proposed rulemaking in the
The EPA is taking final action to revise the definition of regulated pollutant (for presumptive fee calculation) in 40 CFR 70.2 and regulated pollutant (for fee calculation) in 40 CFR 71.2 to exempt GHG emissions. This regulatory amendment will have the effect of excluding GHG emissions from being subject to the statutory ($/ton) fee rate set for the presumptive minimum calculation requirement of part 70 and the fee calculation requirements of part 71. We received supportive comments from the majority of public commenters, including state and local permitting authorities and others, on revising the operating permit rules to exempt GHGs from the emission-based calculations that use the statutory fee rates. We are finalizing this portion of the proposal for the same reasons we explained in the proposal notice, including that leaving these regulations unchanged would have resulted in the collection of fee revenue far beyond the reasonable costs of an operating permit program. The EPA believes that these revisions (in conjunction with the GHG adjustment, see below) are consistent with the CAA requirements for fees pursuant to the authority of section 502(b)(3)(B)(i).
Some members of the public opposed the proposed GHG exemption for reasons including that it may limit permitting authorities' ability to charge sufficient fees to cover the cost of GHG permitting
The EPA is finalizing GHG adjustment option 1 because we believe it will result in a system for the calculation of costs for part 70 and fees for part 71 that is most directly related to the costs of GHG permitting. The EPA has determined that some adjustment to cost and fee accounting is important because the recent addition of GHG emissions to the operating permitting program does add new burdens for permitting authorities. Although GHG adjustment option 3 (no GHG permitting fee adjustments) was supported by many industrial commenters, the EPA rejected it because it is in tension with the statutory requirement that permitting authorities collect sufficient fees to cover all the reasonable costs of permitting. See CAA section 502(b)(3)(A). Some state and local permitting authorities provided comments supporting option 1, while others supported option 2, and some supported either option, stating no preference. Also, a few state and local permitting authorities supported finalizing no adjustment and a few others asked for flexibility to set fee adjustments not proposed by the EPA, but that they believed would be appropriate for their program.
The EPA is finalizing option 1 instead of option 2 because the option 1 adjustments are based on the actual costs for permitting authorities to process specific actions that require GHG reviews. The option 2 approach, which would have added a 7 percent surcharge to the $/ton rate used in the fee-related calculations, may have been administratively easier to implement, but is tied to the emissions of non-GHG air pollutants, which are not directly related to the costs of GHG permitting.
Consistent with CAA section 502(b)(3)(B)(i), the Administrator has determined that the final rule's approach of exempting GHG emissions from fee-related calculations and accounting for the GHG permitting costs through option 1 will result in fees that will cover the reasonable costs of the permitting programs.
The EPA is revising the part 70 regulations through this final action, specifically 40 CFR 70.9(b)(2), to modify the presumptive minimum approach to add the activity-based cost of GHG permitting activities, outlined in the revised 40 CFR 70.9(b)(2)(v), to the emissions-based calculation of 40 CFR 70.9(b)(2)(i), which is being revised to now exclude GHG emissions. To determine the activity-based GHG adjustment under 40 CFR 70.9(b)(2)(v), the permitting authority will multiply the burden hours for each activity (set forth in the regulation) by the cost of staff time (in $ per hour), including wages, benefits, and overhead, as determined by the state, for the particular activities undertaken during the particular time period.
States that implement the presumptive minimum approach will need to follow the final rule's option 1 approach.
Consistent with 40 CFR 70.4(i), a state that wishes to change its operating permit program as a result of this final rule must apprise the EPA. The EPA will review the materials submitted concerning the change and decide if a formal program revision process is needed and will inform the state of next steps. The communication apprising the EPA of any such changes should include at least a narrative description of the change and any other information that will assist the EPA in its assessment of the significance of the changes. Certain changes, such as switching from the presumptive minimum method to a detailed accounting method, will be considered substantial program revisions and be subject to the requirements of 40 CFR 70.4(i)(2).
With respect to the part 71 program, in this final action the EPA is revising 40 CFR 71.9(c) to require each part 71 source to pay an annual fee which is the sum of the activity-based fee of 40 CFR 71.9(c)(8) and the emissions-based fee of 40 CFR 71.9(c)(1)-(4),
The final rule implements the option 1 approach by listing three activities performed by permitting authorities that involve GHG reviews. The following describes the activities as described in our proposal and certain clarifications we are making in the final rule to ensure consistent implementation.
The EPA is finalizing that the first listed activity under option 1 is “GHG completeness determination (for initial permit or updated application).” This activity must be counted for each new initial permit application, even for applications that do not include GHGs emissions or applicable requirements, since an important part of any completeness determination will be to determine that GHG emissions and applicable requirements have been properly addressed, as needed, in the application. The fee for this activity is a one-time charge that covers the initial application and any supplements or updates. The EPA believes that a single charge for a GHG completeness determination will be adequate to cover the reasonable costs for a permitting authority to review an initial application and any subsequent application updates related to initial permit issuance; thus, any updates to an initial application are included in a single “GHG completeness determination,” rather than as a separate activity for which the source would be charged in addition to the completeness determination for the initial application. This is an important distinction because many sources submit multiple permit application updates, either voluntarily or as required by the permitting authority, during application review, many of which do not require a separate or comprehensive completeness determination.
The EPA is finalizing regulatory text that would describe the second listed activity as “GHG evaluation for a permit modification or related permit action.”
The EPA is finalizing the third activity as “GHG evaluation at permit renewal.” This activity covers the processing of all permit renewal applications and will involve evaluations of whether any GHG applicable requirements are properly included.
Some members of the public commented that finalizing a GHG adjustment would inappropriately
Despite some comments received to the contrary, the EPA does not believe it is appropriate to delay the finalization of the GHG adjustment. The EPA does not believe such delays would be consistent with CAA section 502(b)(3)(A) because states have been incurring costs attributable to GHG permitting for several years now and increased fees must be collected to cover the increased costs. The regulatory changes being finalized in this action provide the states with optimal flexibility and sufficient funding to implement their GHG permitting programs. Some commenters had specifically stated that the EPA should delay finalization of this rule until the completion of the next ICR renewal process. While we do not believe delaying this rule is appropriate, as explained above, the EPA notes that we remain committed to collecting and analyzing additional data on costs attributable to GHG permitting for operating permit programs. We may adjust the GHG cost adjustments in future rulemakings if necessary to comply with the requirements of the Act.
As an alternative to the options proposed by the EPA, some commenters asserted that the EPA should make a GHG cost adjustment using a separate, but reduced fee rate ($/ton) for GHGs. We, however, believe that the option 1 approach of the final rule will be more equitable for sources and more representative of actual costs because option 1 considers the costs of the actual permitting activities performed by a particular permitting authority, while any emissions-based approach would not be as directly related to actual costs incurred by permitting authorities.
Some commenters alleged that the EPA's proposal on adjustments to the operating permit programs was vague. The EPA provided a thorough discussion of our rationale in the proposal, including the basis for the GHG adjustments, and we proposed regulatory text to implement our proposal. We explained in the proposal that support for the cost adjustment for GHGs under option 1 is contained in several analyses performed by the EPA and approved by the OMB related to the effect of the addressing GHG requirements in operating permits. These analyses have been placed in the docket for this rulemaking. The analyses include: The Regulatory Impact Assessment (RIA) for the Tailoring Rule (see Regulatory Impact Analysis for the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, Final Report, May 2010); the part 70 ICR change request for the Tailoring Rule (which was based on the RIA for the Tailoring Rule); and the current ICR for part 70 (EPA ICR number 1587.12; OMB control number 2060-0243).
Several commenters asked that we make changes to the option 1 approach that we proposed, such as adding new activities or decreasing the costs we assumed for the proposal. In response to these comments, we note that we received no quantitative data or other information from commenters that we believe demonstrates the need to revise the list of activities we included under option 1 or the burden hour assumptions under option 1 for the activities. Note that to promote consistent implementation of the final option 1 approach, the preamble describes elsewhere a few clarifications concerning the activities under option 1 and one minor revision to the regulatory text of one of the activities.
Since the EPA's proposed rulemaking, the Supreme Court decided in
We are also finalizing the proposed addition of text within 40 CFR part 60, subpart TTTT, to clarify that the fee pollutant for operating permit purposes is GHG (as defined in 40 CFR 70.2 and 71.2). We are finalizing these provisions to add clarity to our regulations and to avoid the potential need for possible future rulemakings to adjust the title V fee regulations if any constituent of GHG, other than CO
The EPA is taking no action at this time on the proposal to move the definitions of “Greenhouse gases (GHG)” within the definition of “Subject to regulation” in 40 CFR parts 70 and 71. No public comments were received on this proposed clarification; however, subsequent to the proposal, on June 23, 2014, the Supreme Court in
In response to the Supreme Court decision and the D.C. Circuit's amended judgment, the EPA intends to conduct future rulemaking action to make the appropriate revisions to the operating permit rules. As part of any such future rulemaking action, the EPA may consider finalizing the proposal to move the definitions of GHGs within the operating permit rules.
Fossil fuel-fired EGUs are, or potentially will be, impacted by several other recently finalized or proposed EPA rules.
On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to reduce emissions of toxic air pollutants from new and existing coal- and oil-fired EGUs. The MATS rule will reduce emissions of heavy metals, including mercury (Hg), arsenic (As), chromium (Cr), and nickel (Ni); and acid gases, including hydrochloric acid (HCl) and hydrofluoric acid (HF). These toxic air pollutants, also known as hazardous air pollutants or air toxics, are known to cause, or suspected of causing, damage nervous system damage, cancer, and other serious health effects. The MATS rule will also reduce SO
New or reconstructed EGUs (
Existing sources subject to the MATS rule were required to begin meeting the rule's requirements on April 16, 2015. Controls that will achieve the MATS performance standards are being installed on many units. Certain units, especially those that operate infrequently, may be considered not worth investing in given today's electricity market, and are closing. The final MATS rule provided a foundation on which states and other permitting authorities could rely in granting an additional, fourth year for compliance provided for by the CAA. States report that these fourth year extensions are being granted. In addition, the EPA issued an enforcement policy that provides a clear pathway for reliability-critical units to receive an administrative order that includes a compliance schedule of up to an additional year, if it is needed to ensure electricity reliability.
The CSAPR requires states to take action to improve air quality by reducing SO
On May 19, 2014, the EPA issued a final rule under section 316(b) of the Clean Water Act (33 U.S. Code section 1326(b)) (referred to hereinafter as the 316(b) rule.) The rule was published on August 15, 2014 (79 FR 48300; August 15, 2014), and became effective October 14, 2014. The 316(b) rule establishes new standards to reduce injury and death of fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities.
On December 19, 2014, the EPA issued the final rule for the disposal of coal combustion residuals from electric utilities. The rule provides a comprehensive set of requirements for the safe disposal of coal combustion residuals (CCRs), commonly known as coal ash, from coal-fired power plants. The CCR rule establishes technical requirements for existing and new CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating solid waste. New CCR landfills and surface impoundments are required to meet the technical criteria before any CCR is placed into the unit. Existing CCR surface impoundments and landfills are subject to implementation timeframes established in the rule for the individual technical criteria. For additional information regarding the CCR rule, see Section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing along with this rule.
The EPA is reviewing public comments and working to finalize the proposed SE ELG rule which will impact fossil fuel-fired EGUs. In 2013, the EPA proposed the SE ELG rule (78 FR 34432; June 7, 2013) to strengthen the controls on discharges from certain steam electric power plants by revising technology-based effluent limitations guidelines and standards for the steam electric power generating point source category. The proposed regulation, which includes new requirements for both existing and new generating units, would reduce impacts to human health and the environment by reducing the amount of toxic metals and other pollutants currently discharged to surface waters from power plants. The EPA intends to take final action on the proposed rule by September 30, 2015. Section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneously with this rule includes additional information regarding the SE ELG rule.
The EPA recognizes the importance of assuring that each of the rules described above can achieve its intended environmental objectives in a commonsense, cost-effective manner, consistent with underlying statutory requirements, and while assuring a reliable power system. Executive Order (E.O.) 13563, “Improving Regulation and Regulatory Review,” issued on January 18, 2011, states that “[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote . . . coordination, simplification, and harmonization.” E.O. 13563 further states that “[e]ach agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation.” Within the EPA, we are paying careful attention to the interrelatedness and potential impacts on the industry, reliability and cost that these various rulemakings can have.
As discussed in earlier sections of this preamble, the EPA has identified potential alternative compliance pathways for affected newly constructed, modified, and reconstructed fossil fuel-fired steam generating units. We are finalizing an emission standard for newly constructed highly efficient fossil fuel-fired steam generating units that can be met by capturing and storing approximately 16 to 23 percent of the CO
The EPA is also endeavoring to enable EGUs to comply with applicable obligations under other power sector rules as efficiently as possible (
In light of the compliance flexibilities we are offering in this action, we believe that sources will have ample opportunity to use cost-effective regulatory strategies and build on their longstanding, successful records of complying with multiple CAA, CWA, and other environmental requirements, while assuring an adequate, affordable, and reliable supply of electricity.
As explained in the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-452/R-15-005, August 2015) (RIA), available data indicate that, even in the absence of the standards of performance for newly constructed EGUs, existing and anticipated economic conditions will lead electricity generators to choose new generation technologies that will meet the standards without installation of additional controls. Therefore, based on the analysis presented in Chapter 4 of the RIA, the EPA projects that this final rule will result in negligible CO
As also explained in the RIA for this final rule, the EPA also expects that few sources will trigger either the NSPS modification or reconstruction provisions that we are finalizing in this rule. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
As explained immediately above, the EPA does not anticipate that this final rule will result in notable CO
As also explained immediately above, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis.
New steam generating EGUs that choose to comply with the final standard of performance by implementing partial post-combustion CCS are likely to use commercially-available amine-based capture systems. Some concern has been raised regarding emissions of amines and amine degradation by-products (
Research performed by MHI at Alabama Power's Plant Barry indicated that an increasing SO
Consistent with the requirements of section 7(a)(2) of the Endangered Species Act (ESA), the EPA has also considered the effects of this rule and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to listed endangered or threatened species or the designated critical habitat of such species and whether consultation with the U.S. Fish and Wildlife Service (FWS) and/or National Marine Fisheries Service (together, the Services) is required by the ESA. Section 7(a)(2) of the ESA requires federal agencies, in consultation with the Service(s), to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of federally listed endangered or threatened species or result in the destruction or adverse modification of designated critical habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant implementing regulations, ESA section 7(a)(2) applies only to actions where there is discretionary federal involvement or control. 50 CFR 402.03. Further, under the regulations consultation is required only for actions that “may affect” listed species or designated critical habitat. 50 CFR 402.14. Consultation is not required where the action has no effect on such species or habitat. Under this standard, it is the federal agency taking the action that evaluates the action and determines whether consultation is required.
The EPA notes that the projected environmental effects of this final action are positive: Reductions in overall GHG emissions, and reductions in PM and ozone-precursor emissions (SO
The EPA notes that the emission reductions achieved by the rule are projected to be minor. See Section XIII.F and G. below, and RIA chapter 4. Although the final rule imposes substantial controls on CO
With respect to the projected GHG emission reductions, the EPA does not believe that such minor reductions trigger ESA consultation requirements under section 7(a)(2). In reaching this conclusion, the EPA is mindful of significant legal and technical analysis undertaken by FWS and the U.S. Department of the Interior (DOI) in the context of listing the polar bear as a threatened species under the ESA. In that context, in 2008, FWS and DOI expressed the view that the best scientific data available were insufficient to draw a causal connection between GHG emissions and effects on the species in its habitat.
The EPA has also previously considered issues relating to GHG emissions in connection with the requirements of ESA section 7(a)(2) and has supplemented DOI's analysis with additional consideration of GHG modeling tools and data regarding listed species. The EPA evaluated this same issue in the context of the light duty vehicle GHG emission standards for model years 2012-2016 and 2017-2025. There the agency projected GHG emission reductions many orders of magnitude greater over the lifetimes of the model years in question
The EPA received a comment on the proposal referencing a prior letter sent to the EPA by three U.S. Senators,
This final rule is not anticipated to have a notable effect on the supply, distribution, or use of energy. As previously stated, the EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this rule even in its absence, primarily NGCC units, because of existing and expected market conditions. As also previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis.
This final rule is not anticipated to have notable impacts on water or solid waste. As we have noted, the EPA believes that utilities and project developers will choose to build new EGUs that comply with the regulatory requirements of this rule even in its absence, primarily through the construction of new NGCC units. As also previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Still there are expected to be a small number of coal plants with CCS and the use of CCS systems (especially post-combustion system) will increase the amount of water used at the facility. If those plants utilize partial CCS to meet the final standard of performance (
For steam generating EGUs, the EPA has carefully analyzed the costs of meeting the promulgated standard of performance for a highly efficient SCPC
In addition, the EPA believes the standards of performance for modified and reconstructed EGUs will have minimal associated compliance costs, because, as previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis.
The EPA does not anticipate that this final rule will result in notable CO
As previously stated, the EPA anticipates few units will trigger the NSPS modification or reconstruction provisions. As with the new source standards, the EPA does not expect macroeconomic or employment impacts as a result of the standards.
We are not projecting direct monetized climate benefits in terms of CO
As also previously stated, the EPA anticipates few units will trigger the NSPS modification or reconstruction provisions. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
Additional information about these Statutory and Executive Orders can be found at
This final action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. It is a significant regulatory action because it raises novel legal or policy issues arising out of legal mandates. Any changes made in response to OMB recommendations have been documented in the established dockets for this action under Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No. EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units). The EPA prepared an economic analysis of the potential costs and benefits associated with this action. This analysis, which is contained in the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-452/R-15-005, August 2015), is available in both dockets.
The EPA does not anticipate that this final action will result in any notable compliance costs. Specifically, we believe that the standards for newly constructed fossil fuel-fired EGUs (electric utility steam generating units and natural gas-fired stationary combustion turbines) will have negligible costs associated with it over a range of likely sensitivity conditions because electric power companies will choose to build new EGUs that comply with the regulatory requirements of this action even in the absence of the action, because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal-fired steam generating units without CCS to be built in the absence of this action. However, because some companies may choose to construct coal or other fossil fuel-fired EGUs, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired EGU with CCS.
The EPA also believes that the standards for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because, as previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis (through 2022). In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
The information collection activities in this final action have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number 2465.03. Separate ICR documents were prepared and submitted to OMB for the proposed standards for newly constructed EGUs (EPA ICR number 2465.02) and the proposed standards for modified and reconstructed EGUs (EPA ICR number 2506.01). Because the CO
The recordkeeping and reporting requirements in this final action are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to agency policies set forth in 40 CFR part 2, subpart B.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the agency will announce that approval in the
This final action will impose minimal new information collection burden on owners and operators of affected newly constructed fossil fuel-fired EGUs (steam generating units and stationary combustion turbines) beyond what those sources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501
The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any newly constructed coal-fired steam generating units that commenced construction after proposal (January 8, 2014) to commence operation over the 3-year period covered by this ICR. We estimate that 12 affected newly constructed NGCC units and 25 affected newly constructed natural gas-fired simple cycle combustion turbines will commence operation during that time period. As a result of this final action, owners or operators of those newly constructed units will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months.
This final action is not expected to impose an information collection burden under the provisions of the PRA on owners and operators of affected modified and reconstructed fossil fuel-fired EGUs (steam generating units and stationary combustion turbines). As previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired electric utility steam generating units or stationary combustion turbines will take actions that would constitute modifications or reconstructions as defined under the EPA's NSPS regulations. Accordingly, the standards for modified and reconstructed EGUs are not anticipated to impose any information collection burden over the 3-year period covered by this ICR. We have estimated, however, the information collection burden that would be imposed on an affected EGU if it was modified or reconstructed.
Although not anticipated, if an EGU were to modify or reconstruct, this final action would impose minimal information collection burden on those affected EGUs beyond what they would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As described above, the OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations. Apart from certain reporting costs to comply with the emission standards under the rule, there would be no new information collection costs, as the information required by the final rule is already collected and reported by other regulatory programs.
As stated above, although the EPA expects few sources will trigger either the NSPS modification or reconstruction provisions, if an EGU were to modify or reconstruct during the 3-year period covered by this ICR, the owner or operator of the EGU will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months. The annual reporting burden for such a unit is estimated to be $1,333 and 16 labor hours. There are no annualized capital costs or O&M costs associated with burden for modified or reconstructed EGUs.
The annual information collection burden for newly constructed, modified, and reconstructed EGUs consists only of reporting burden as explained above. The annual reporting burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $60,977 and 651 labor hours. There are no annualized capital costs or O&M costs associated with burden for newly constructed, modified, or reconstructed EGUs. Average burden hours per response are estimated to be 7 hours. The total number of respondents over the 3-year ICR period is estimated to be 62.
I certify that this final 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 EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. RIA Chapter 4. The EPA does not project any new coal-fired steam generating units without CCS to be built. We expect that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. We do not include an analysis of the illustrative impacts on small entities that may result from implementation of the final rule because we anticipate negligible compliance costs over a range of likely sensitivity conditions as a result of the standards for newly constructed EGUs. Thus the cost-to-sales ratios for any affected small entity would be zero costs as compared to annual sales revenue for the entity. Accordingly, there are no anticipated
The EPA expects few fossil fuel-fired electric utility steam generating units to trigger the NSPS modification provisions in the period of analysis. An NSPS modification is defined as a physical or operational change that increases the source's maximum achievable hourly rate of emissions. The EPA does not believe that there are likely to be EGUs that will take actions that would constitute modifications as defined under the EPA's NSPS regulations.
In addition, the EPA expects few reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. Reconstruction occurs when a single project replaces components or equipment in an existing facility and exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility.
In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources, including any that are owned by small entities. (See the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-452/R-15-005, August 2015).
This final action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments.
The EPA believes the final rule will have negligible compliance costs on owners and operators of newly constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. (See the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-452/R-15-005, August 2015) for further discussion of sensitivities.)
As previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources. (See the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-452/R-15-005, August 2015).)
We have therefore concluded that the standards for newly constructed, modified, and reconstructed EGUs do not impose enforceable duties on any state, local or tribal governments, or the private sector, that may result in expenditures by state, local and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. We have also concluded that this action does not have regulatory requirements that might significantly or uniquely affect small governments. The threshold amount established for determining whether regulatory requirements could significantly affect small governments is $100 million annually and, as stated above, we have concluded that the final action will not result in expenditures of $100 million or more in any one year. Specifically, the EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. Further, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis.
This final 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. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. We, therefore, anticipate that the final rule will impose minimal compliance costs.
This final action does not have tribal implications as specified in Executive Order 13175. The final rule will impose requirements on owners and operators of newly constructed, modified, and reconstructed EGUs. The EPA is aware of three facilities with coal-fired steam generating units, as well as one facility with natural gas-fired stationary combustion turbines, located in Indian Country, but is not aware of any EGUs owned or operated by tribal entities. We note that because the rule addresses CO
Nevertheless, because the EPA is aware of Tribal interest in carbon pollution standards for the power sector and, consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA offered consultation with tribal officials during
The EPA also offered consultation to the leaders of all federally recognized tribes after the proposed action for newly constructed EGUs was signed on September, 20, 2013. On November 1, 2013, the EPA sent letters to tribal leaders that provided information regarding the EPA's development of carbon pollution standards for new, modified, reconstructed and existing EGUs and offered consultation. No tribes requested consultation regarding the standards for newly constructed EGUs.
In addition to offering consultation, the EPA also conducted outreach to tribes during development of this rule. The EPA held a series of listening sessions prior to proposal of GHG standards for newly constructed EGUs. Tribes participated in a session on February 17, 2011, with the state agencies, as well as in a separate session with tribes on April 20, 2011. The EPA also held a series of listening sessions prior to proposal of GHG standards for modified and reconstructed EGUs and GHG emission guidelines for existing EGUs. Tribes participated in a session on September 9, 2013, together with the state agencies, as well as in a separate tribe-only session on September 26, 2013. In addition, an outreach meeting was held on September 9, 2013, with tribal representatives from some of the federally recognized tribes. The EPA also met with tribal environmental staff with the National Tribal Air Association, by teleconference, on July 25, 2013, and December 19, 2013. Additional detail regarding this stakeholder outreach is included in the preamble to the proposed emission guidelines for existing EGUs (79 FR 34830, June 18, 2014).
This action is not subject to Executive Order 13045 because it is not economically significant as defined in Executive Order 12866. While the action is not subject to Executive Order 13045, the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children.
CO
The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that certain populations and lifestages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience.
These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
More detailed information on the impacts of climate change to human health and welfare is provided in Section II.A of this preamble.
This final action is not a “significant energy action” because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. See Section V.O.3 above. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. Thus, this action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry.
This final action involves technical standards. The EPA has decided to use 10 voluntary consensus standards (VCS) in the final rule.
One VCS, American National Standards Institute (ANSI) Standard C12.20, “American National Standard for Electricity Meters—0.2 and 0.5 Accuracy Classes,” is cited in the final rule to assure consistent monitoring of electric output. This standard establishes the physical aspects and acceptable performance criteria for 0.2 and 0.5 accuracy class electricity meters. This standard is available at
Six VCS, ASTM Methods D388-99, “Standard Classification of Coals by Rank”; D396-98, “Standard Specification for Fuel Oils”; D975-08a, “Standard Specification for Diesel Fuel Oils”; D3699-08, “Standard Specification for Kerosine”; D6751-11b,
Two VCS, American Society of Mechanical Engineers (ASME) Performance Test Codes PTC 22-2014, “Performance Test Codes on Gas Turbines” and PTC 46-1996, “Performance Test Codes on Overall Plant Performance” are cited in the final rule for their guidance on measuring the performance of stationary combustion turbines. PTC-22 provides directions and rules for conduct and report of results of thermal performance tests for open cycle simple cycle combustion turbines. The object is to determine the thermal performance of the combustion turbine when operating at test conditions, and correcting these test results to specified reference conditions. PTC 22 provides explicit procedures for the determination of the following performance results: corrected power,
One VCS, International Organization for Standardization method ISO 2314:2009, “Gas Turbines—Acceptance Tests” is cited in the final rule for its guidance on determining performance characteristics of stationary combustion turbines. ISO 2314 specifies guidelines and procedures for preparing, conducting and reporting thermal-acceptance tests in order to determine and/or verify electrical power output, mechanical power, thermal efficiency (heat rate), turbine exhaust gas energy and/or other performance characteristics of open-cycle simple cycle combustion turbines using combustion systems supplied with gaseous and/or liquid fuels as well as closed-cycle and semi-closed-cycle simple cycle combustion turbines. It can also be applied to simple cycle combustion turbines in combined cycle power plants or in connection with other heat recovery systems. ISO 2314 includes procedures for the determination of the following performance parameters, corrected to the reference operating parameters: electrical or mechanical power output (gas power, if only gas is supplied), thermal efficiency or heat rate; and combustion turbine engine exhaust energy (optionally exhaust temperature and flow). This standard is available at
Since no EPA Methods were used, there was no need for a NTTAA search. The rule also requires use of appendices A, B, D, F and G to 40 CFR part 75 and the procedures under 40 CFR 98.33; these appendices contain standards that have already been reviewed under the NTTAA.
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA has this goal for all communities and persons across this Nation. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn, and work.
Leading up to this rulemaking the EPA summarized the public health and welfare effects of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the Administrator considered climate change risks to minority or low-income populations, finding that certain parts of the population may be especially vulnerable based on their circumstances. Populations that were found to be particularly vulnerable to
The record for the 2009 Endangerment Finding summarizes the strong scientific evidence in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies that the potential impacts of climate change raise environmental justice issues. These reports concluded that poor communities can be especially vulnerable to climate change impacts because they tend to have more limited adaptive capacities and are more dependent on climate-sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particularly those impacted by degradation of natural and cultural resources within established reservation boundaries and threats to traditional subsistence lifestyles. Tribal communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. The 2009 Endangerment Finding record also specifically noted that Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities are already experiencing disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods and well-being.
The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low-income populations in the United States.
IPCC, 2014:
IPCC, 2014:
As the scientific literature presented above and in the Endangerment Finding illustrates, low income communities and some communities of color are especially vulnerable to the health and other adverse impacts of climate change.
The EPA believes the human health or environmental risk addressed by this final action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. The final rule limits GHG emissions from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and newly constructed and modified stationary combustion turbines by establishing national emission standards for CO
The EPA has determined that the final rule will not result in disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because the rule is not anticipated to notably affect the level of protection provided to human health or the environment. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly built natural gas-fired stationary combustion turbines will meet the standards. In addition, as previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. This final rule will ensure that, to whatever extent there are newly constructed, modified, and reconstructed EGUs, they will use the best performing technologies to limit emissions of CO
This final 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).
In this action, as discussed above in Sections IV and VI, the EPA is issuing final standards of performance for affected fossil fuel-fired steam generating EGUs that implement modifications resulting in an increase of CO
The EPA is also, in this action, withdrawing proposed standards for modified stationary combustion turbines. A detailed rationale for the withdrawal of these proposed standards is provided in Section IX above.
The proposed standards for modified fossil fuel-fired EGUs that the EPA is withdrawing in this action were published in the
The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedure, Air pollution control, Reporting and recordkeeping requirements.
Environmental protection, Greenhouse gases and monitoring, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, title 40, chapter I, parts 60, 70, 71, and 98 of the Code of the Federal Regulations are amended as follows:
42 U.S.C. 7401
The revisions and additions read as follows:
(d) The following material is available for purchase from the American National Standards Institute (ANSI), 25 W. 43rd Street, 4th Floor, New York, NY 10036, Telephone (212) 642-4980, and is also available at the following Web site:
(1) ANSI No. C12.20-2010 American National Standard for Electricity Meters—0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR approved for § 60.5535(d).
(2) [Reserved]
(g) * * *
(15) ASME PTC 22-2014, Gas Turbines: Performance Test Codes, (Issued December 31, 2014), IBR approved for § 60.5580.
(16) ASME PTC 46-1996, Performance Test Code on Overall Plant Performance, (Issued October 15, 1997), IBR approved for § 60.5580.
(h) * * *
(37) ASTM D388-99 (Reapproved 2004)
(42) ASTM D396-98, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b, 60.41c, 60.111(b), 60.111a(b), and 60.5580.
(46) ASTM D975-08a, Standard Specification for Diesel Fuel Oils, IBR approved for §§ 60.41b 60.41c, and 60.5580.
(138) ASTM D3699-08, Standard Specification for Kerosine, including Appendix X1, (Approved September 1, 2008), IBR approved for §§ 60.41b, 60.41c, and 60.5580.
(187) ASTM D6751-11b, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1 through X3, (Approved July 15, 2011), IBR approved for §§ 60.41b, 60.41c, and 60.5580.
(190) ASTM D7467-10, Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20), including Appendices X1 through X3, (Approved August 1, 2010), IBR approved for §§ 60.41b, 60.41c, and 60.5580.
(m) * * *
(1) ISO 2314:2009(E), Gas turbines-Acceptance tests, Third edition (December 15, 2009), IBR approved for § 60.5580.
This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit,
(a) Except as provided for in paragraph (b) of this section, the GHG standards included in this subpart apply to any steam generating unit, IGCC, or stationary combustion turbine that commenced construction after January 8, 2014 or commenced reconstruction after June 18, 2014 that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. The GHG standards included in this subpart also apply to any steam generating unit or IGCC that commenced modification after June 18, 2014 that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section.
(1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either alone or in combination with any other fuel); and
(2) Serves a generator or generators capable of selling greater than 25 MW of electricity to a utility power distribution system.
(b) You are not subject to the requirements of this subpart if your affected EGU meets any of the conditions specified in paragraphs (b)(1) through (10) of this section.
(1) Your EGU is a steam generating unit or IGCC that is currently and always has been subject to a federally enforceable permit condition limiting annual net-electric sales to no more than one-third of its potential electric output or 219,000 MWh, whichever is greater.
(2) Your EGU is capable of combusting 50 percent or more non-fossil fuel and is also subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less.
(3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit condition limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater.
(4) Your EGU serves a generator along with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less.
(5) Your EGU is a municipal waste combustor that is subject to subpart Eb of this part.
(6) Your EGU is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.
(7) Your EGU is a steam generating unit or IGCC that undergoes a modification resulting in an hourly increase in CO
(8) Your EGU is a stationary combustion turbine that is not capable of combusting natural gas (
(9) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014.
(10) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014.
(a) The pollutants regulated by this subpart are greenhouse gases. The greenhouse gas standard in this subpart is in the form of a limitation on emission of carbon dioxide.
(b)
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter.
(3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2.
(a) For each affected EGU subject to this subpart, you must not discharge from the affected EGU any gases that contain CO
(b) Except as specified in paragraphs (c) and (d) of this section, you must comply with the applicable gross energy output standard, and your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable gross energy output standard. For the remainder of this subpart (for sources that do not qualify under paragraphs (c) and (d) of this section), where the term “gross or net energy output” is used, the term that applies to you is “gross energy output.”
(c) As an alternate to meeting the requirements in paragraph (b) of this section, an owner or operator of a stationary combustion turbine may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the petition, beginning on the date the Administrator grants the petition, the affected EGU must comply with the applicable net energy output-based standard included in this subpart. Your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable net energy output standard. For the remainder of this subpart, where the term “gross or net energy output” is used, the term that applies to you is “net energy output.” Owners or
(d) Stationary combustion turbines subject to a heat input-based standard in Table 2 of this subpart that are only permitted to burn one or more uniform fuels, as described in paragraph (d)(1) of this section, are only subject to the monitoring requirements in paragraph (d)(1). All other stationary combustion turbines subject to a heat input based standard in Table 2 are subject to the requirements in paragraph (d)(2) of this section.
(1) Stationary combustion turbines that are only permitted to burn fuels with a consistent chemical composition (
(2) Stationary combustion turbines permitted to burn fuels that do not have a consistent chemical composition or that do not have an emission rate of 160 lb CO
Combustion turbines qualifying under § 60.5520(d)(1) are not subject to any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). For all other affected sources, compliance with the applicable CO
(a) You must be in compliance with the emission standards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emission standards only at the end of the applicable operating month, as provided in paragraph (a)(1) of this section.
(1) For each affected EGU subject to a CO
(2) Consistent with § 60.5520(d)(2), if your affected stationary combustion turbine is subject to an input-based CO
(b) At all times you must operate and maintain each affected EGU, including associated equipment and monitors, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart, and inspection of the EGU.
(c) Within 30 days after the end of the initial compliance period (
(1) For an affected EGU that commences commercial operation (as defined in § 72.2 of this chapter) on or after October 23, 2015, the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under:
(i) Section 63.5555(c)(3)(i), for units subject to the Acid Rain Program; or
(ii) Section 63.5555(c)(3)(ii)(A), for units that are not in the Acid Rain Program.
(2) For an affected EGU that has commenced COMMERCIAL operation (as defined in § 72.2 of this chapter) prior to October 23, 2015:
(i) If the date on which emissions reporting is required to begin under § 75.64(a) of this chapter has passed prior to October 23, 2015, emissions reporting shall begin according to § 63.5555(c)(3)(i) (for Acid Rain program units), or according to § 63.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain Program). The first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which the rule becomes effective; or
(ii) If the date on which emissions reporting is required to begin under § 75.64(a) of this chapter occurs on or after October 23, 2015, then the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under § 63.5555(c)(3)(ii)(A).
(3) For a modified or reconstructed EGU that becomes subject to this subpart, the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under § 63.5555(c)(3)(iii).
(a) Combustion turbines qualifying under § 60.5520(d)(1) are not subject to any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). If your combustion turbine uses non-uniform fuels as specified under § 60.5520(d)(2), you must monitor heat input in accordance with paragraph (c)(1) of this section, and you must monitor CO
(b) You must determine the hourly CO
(1) For an affected coal-fired EGU or for an IGCC unit you must, and for all other affected EGUs you may, install, certify, operate, maintain, and calibrate a CO
(2) For each continuous monitoring system that you use to determine the CO
(3) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO
(4) You must select an appropriate reference method to setup (characterize) the flow monitor and to perform the on-going RATAs, in accordance with part 75 of this chapter. If you use a Type-S pitot tube or a pitot tube assembly for the flow RATAs, you must calibrate the pitot tube or pitot tube assembly; you may not use the 0.84 default Type-S pitot tube coefficient specified in Method 2.
(5) Calculate the hourly CO
(i) Begin with the hourly CO
(ii) Next, multiply each hourly CO
(iii) Finally, multiply the result from paragraph (b)(5)(ii) of this section by 909.1 to convert it from tons of CO
(iv) The hourly CO
(c) If your affected EGU exclusively combusts liquid fuel and/or gaseous fuel, as an alternative to complying with paragraph (b) of this section, you may determine the hourly CO
(1) If you are subject to an output-based standard and you do not install CEMS in accordance with paragraph (b) of this section, you must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.
(2) For each measured hourly heat input rate, use Equation G-4 in appendix G to part 75 of this chapter to calculate the hourly CO
(3) For each “valid operating hour” (as defined in § 60.5540(a)(1), multiply the hourly tons/h CO
(4) The hourly CO
(5) If you operate a combustion turbine firing non-uniform fuels, as an alternative to following paragraphs (c)(1) through (4) of this section, you may determine CO
(i) Units firing fuel gas may determine the heat input during the compliance period following the procedure under § 60.107a(d) and convert this heat input to CO
(ii) You may use the procedure for determining CO
(d) Consistent with § 60.5520, you must determine the basis of the emissions standard that applies to your
(1) If you operate a source subject to an emissions standard established on an output basis (
(2) If you operate a source subject to an emissions standard established on a heat-input basis (
(i) Appendix D to part 75 of this chapter;
(ii) The procedures for monitoring heat input under § 60.107a(d);
(iii) If you monitor CO
(e) Consistent with § 60.5520, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly gross or net energy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU. Alternatively, if the EGUs are identical, you may apportion the combined hourly gross or net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU.
(f) In accordance with §§ 60.13(g) and 60.5520, if two or more affected EGUs that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard in Table 1 or 2 of this subpart, you may monitor the hourly CO
(g) In accordance with §§ 60.13(g) and 60.5520 if the exhaust gases from an affected EGU that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO
(a) In accordance with § 60.5520, if you are subject to an output-based emission standard or you burn non-uniform fuels as specified in § 60.5520(d)(2), you must demonstrate compliance with the applicable CO
(1) Each compliance period shall include only “valid operating hours” in the compliance period,
(i) “Valid data” (as defined in § 60.5580) are obtained for all of the parameters used to determine the hourly CO
(ii) The corresponding hourly gross or net energy output value is also valid data (
(2) You must exclude operating hours in which:
(i) The substitute data provisions of part 75 of this chapter are applied for any of the parameters used to determine the hourly CO
(ii) An exceedance of the full-scale range of a continuous emission monitoring system occurs for any of the parameters used to determine the hourly CO
(iii) The total gross or net energy output (P
(3) For each compliance period, at least 95 percent of the operating hours in the compliance period must be valid operating hours, as defined in paragraph (a)(1) of this section.
(4) You must calculate the total CO
(5)
(i) Calculate P
(ii) If applicable to your affected EGU (for example, for combined heat and power), you must calculate (Pt)
(6)
(i) In accordance with § 60.5520 if you are subject to an output-based standard, you must calculate the total gross or net energy output for the affected EGU's compliance period by summing the hourly gross or net energy output values for the affected EGU that you determined under paragraph (a)(5) of this section for all of the valid operating hours in the applicable compliance period.
(ii) If you are subject to a heat input-based standard, you must calculate the total heat input for each fuel fired during the compliance period. The calculation of total heat input for each individual fuel must include all valid operating hours and must also be consistent with any fuel-specific procedures specified within your selected monitoring option under § 60.5535(d)(2).
(7) If you are subject to an output-based standard, you must calculate the CO
(b) In accordance with § 60.5520, to demonstrate compliance with the applicable CO
(a) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (3) and 60.19, as applicable to your affected EGU(s) (see Table 3 of this subpart).
(b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable, to your affected EGUs.
(a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable.
(1) For affected EGUs that are required by § 60.5525 to conduct initial and on-going compliance determinations on a 12-operating-month rolling average basis, you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected EGU, you must submit a report for the calendar quarter that includes the twelfth operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter.
(2) In each quarterly report you must include the following information, as applicable:
(i) Each rolling average CO
(ii) If one or more compliance periods end in the quarter, you must identify each operating month in the calendar quarter where your EGU violated the applicable CO
(iii) If one or more compliance periods end in the quarter and there are no violations for the affected EGU, you must include a statement indicating this in the report;
(iv) The percentage of valid operating hours in each 12-operating-month compliance period described in paragraph (a)(1)(i) of this section (
(v) Consistent with § 60.5520, the CO
(vi) Consistent with § 60.5520, an indication whether or not the hourly gross or net energy output (P
(3) In the final quarterly report of each calendar year, you must include the following:
(i) Consistent with § 60.5520, gross energy output or net energy output sold to an electric grid, as applicable to the units of your emission standard, over the four quarters of the calendar year; and
(ii) The potential electric output of the EGU.
(b) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA.
(c)(1) For affected EGUs under this subpart that are also subject to the Acid Rain Program, you must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.
(2) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart.
(3)(i) For all newly-constructed affected EGUs under this subpart that are also subject to the Acid Rain Program, you must begin submitting the quarterly electronic emissions reports described in paragraph (c)(1) of this section in accordance with § 75.64(a) of this chapter,
(A) The date of provisional certification, as defined in § 75.20(a)(3) of this chapter; or
(B) 180 days after the date on which the EGU commences commercial operation (as defined in § 72.2 of this chapter).
(ii) For newly-constructed affected EGUs under this subpart that are not subject to the Acid Rain Program, you must begin submitting the quarterly electronic reports described in paragraph (c)(2) of this section, beginning with data recorded on and after:
(A) The date on which reporting is required to begin under § 75.64(a) of this chapter, if that date occurs on or after October 23, 2015; or
(B) October 23, 2015, if the date on which reporting would ordinarily be required to begin under § 75.64(a) of this chapter has passed prior to October 23, 2015.
(iii) For reconstructed or modified units, reporting of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net energy output data on that date. Otherwise, emissions data reporting shall be on a gross energy output basis until the date that the Client Tool is first able to receive and process net energy output data.
(4) If any required monitoring system has not been provisionally certified by the applicable date on which emissions data reporting is required to begin under paragraph (c)(3) of this section, the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with § 75.4(j) of this chapter, § 75.37(b) of this chapter, or section 2.4 of appendix D to part 75 of this chapter (as applicable). Operating hours in which CO
(d) For affected EGUs subject to the Acid Rain Program, the reports required under paragraphs (a) and (c)(1) of this section shall be submitted by:
(1) The person appointed as the Designated Representative (DR) under § 72.20 of this chapter; or
(2) The person appointed as the Alternate Designated Representative (ADR) under § 72.22 of this chapter; or
(3) A person (or persons) authorized by the DR or ADR under § 72.26 of this chapter to make the required submissions.
(e) For affected EGUs that are not subject to the Acid Rain Program, the owner or operator shall appoint a DR and (optionally) an ADR to submit the reports required under paragraphs (a) and (c)(2) of this section. The DR and ADR must register with the Clean Air Markets Division (CAMD) Business System. The DR may delegate the authority to make the required submissions to one or more persons.
(f) If your affected EGU captures CO
(1) Report in accordance with the requirements of 40 CFR part 98, subpart RR, if injection occurs on-site, or
(2) Transfer the captured CO
(3) Transfer the captured CO
(g) Any person may request the Administrator to issue a waiver of the requirement that captured CO
(a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in § 60.7(b) and (f).
(b)(1) For affected EGUs subject to the Acid Rain Program, you must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.
(2) For affected EGUs that are not subject to the Acid Rain Program, you must also follow the recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter, to the extent that those records provide applicable data for the compliance determinations required under this subpart. Regardless of the prior sentence, at a minimum, the following records must be kept, as applicable to the types of continuous monitoring systems used to demonstrate compliance under this subpart:
(i) Monitoring plan records under § 75.53(g) and (h) of this chapter;
(ii) Operating parameter records under § 75.57(b)(1) through (4) of this chapter;
(iii) The records under § 75.57(c)(2) of this chapter, for stack gas volumetric flow rate;
(iv) The records under § 75.57(c)(3) of this chapter for continuous moisture monitoring systems;
(v) The records under § 75.57(e)(1) of this chapter, except for paragraph (e)(1)(x), for CO
(vi) The records under § 75.58(c)(1) of this chapter, specifically paragraphs (c)(1)(i), (ii), and (viii) through (xiv), for oil flow meters;
(vii) The records under § 75.58(c)(4) of this chapter, specifically paragraphs (c)(4)(i), (ii), (iv), (v), and (vii) through (xi), for gas flow meters;
(viii) The quality-assurance records under § 75.59(a) of this chapter, specifically paragraphs (a)(1) through (12) and (15), for CEMS;
(ix) The quality-assurance records under § 75.59(a) of this chapter, specifically paragraphs (b)(1) through (4), for fuel flow meters; and
(x) Records of data acquisition and handling system (DAHS) verification under § 75.59(e) of this chapter.
(c) You must keep records of the calculations you performed to determine the hourly and total CO
(1) Each operating month (for all affected EGUs); and
(2) Each compliance period, including, each 12-operating-month compliance period.
(d) Consistent with § 60.5520, you must keep records of the applicable data recorded and calculations performed that you used to determine your affected EGU's gross or net energy output for each operating month.
(e) You must keep records of the calculations you performed to determine the percentage of valid CO
(f) You must keep records of the calculations you performed to assess compliance with each applicable CO
(g) You must keep records of the calculations you performed to determine any site-specific carbon-based F-factors you used in the emissions calculations (if applicable).
(a) Your records must be in a form suitable and readily available for expeditious review.
(b) You must maintain each record for 3 years after the date of conclusion of each compliance period.
(c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. Records that are accessible from a central location by a computer or other means that instantly provide access at the site meet this requirement. You may maintain the records off site for the remaining year(s) as required by this subpart.
Notwithstanding any other provision of this chapter, certain parts of the general provisions in §§ 60.1 through 60.19, listed in Table 3 to this subpart, do not apply to your affected EGU.
(a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) through (5) of this section and does not transfer them to the state, local, or tribal agency. In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate.
(1) Approval of alternatives to the emission standards.
(2) Approval of major alternatives to test methods.
(3) Approval of major alternatives to monitoring.
(4) Approval of major alternatives to recordkeeping and reporting.
(5) Performance test and data reduction waivers under § 60.8(b).
As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (general provisions of this part).
(1) For stationary combustion turbines and IGCC, the gross electric or direct mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output.
(2) For steam generating units, the gross electric or mechanical output from the affected EGU(s) (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful thermal output;
(3) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal output on a 12-operating-month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 100 percent of the useful thermal output.
(1) The gross electric sales to the utility power distribution system minus purchased power; or
(2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on an annual basis, the gross electric sales to the utility power
(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales.
(4) Electric sales that that result from a system emergency are not included when calculating net-electric sales.
(1) The net electric or mechanical output from the affected EGU plus 100 percent of the useful thermal output; or
(2) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating-month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output.
42 U.S.C. 7401,
The revision and additions read as follows:
(4) Greenhouse gases.
(b) * * *
(2)(i) The Administrator will presume that the fee schedule meets the requirements of paragraph (b)(1) of this section if it would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and any GHG cost adjustment required under paragraph (b)(2)(v) of this section.
(v)
42 U.S.C. 7401,
The revisions and additions read as follows:
(4) Greenhouse gases.
The revisions and addition read as follows:
(c) * * *
(1) For part 71 programs that are administered by EPA, each part 71 source shall pay an annual fee which is the sum of:
(i) $32 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and
(ii) Any GHG fee adjustment required under paragraph (c)(8) of this section.
(2) * * *
(i) Where the EPA has not suspended its part 71 fee collection pursuant to paragraph (c)(2)(ii) of this section, the annual fee for each part 71 source shall be the sum of:
(A) $24 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and
(B) Any GHG fee adjustment required under paragraph (c)(8) of this section.
(3) For part 71 programs that are administered by EPA with contractor assistance, the per ton fee shall vary depending on the extent of contractor involvement and the cost to EPA of contractor assistance. The EPA shall establish a per ton fee that is based on the contractor costs for the specific part 71 program that is being administered, using the following formula:
Where
Where
(4) For programs that are delegated in part, the fee shall be computed using the following formula:
Where
(8)
42 U.S.C. 7401-7671q.
(h) If you capture a CO
(1) Report the facility identification number associated with the annual GHG report for the subpart D facility;
(2) Report each facility identification number associated with the annual GHG reports for each subpart RR facility to which CO
(3) Report the annual quantity of CO
(d) Facilities subject to § 98.426(h) must retain records of CO
Environmental Protection Agency (EPA).
Final rule.
In this action, the Environmental Protection Agency (EPA) is establishing final emission guidelines for states to follow in developing plans to reduce greenhouse gas (GHG) emissions from existing fossil fuel-fired electric generating units (EGUs). Specifically, the EPA is establishing: Carbon dioxide (CO
This final rule is effective on December 22, 2015.
Ms. Amy Vasu, Sector Policies and Programs Division (D205-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-0107, facsimile number (919) 541-4991; email address:
This final rule is a significant step forward in reducing greenhouse gas (GHG) emissions in the U.S. In this action, the EPA is establishing for the first time GHG emission guidelines for existing power plants. These final emission guidelines, which rely in large part on already clearly emerging growth in clean energy innovation, development and deployment, will lead to significant carbon dioxide (CO
Under the authority of Clean Air Act (CAA) section 111(d), the EPA is establishing CO
States with one or more affected EGUs will be required to develop and implement plans that set emission standards for affected EGUs. The CAA section 111(d) emission guidelines that the EPA is promulgating in this action apply to only the 48 contiguous states and any Indian tribe that has been approved by the EPA pursuant to 40 CFR 49.9 as eligible to develop and implement a CAA section 111(d) plan.
The emission standards in a state's plan may incorporate the subcategory-specific CO
The EPA is promulgating: (1) Subcategory-specific CO
In this summary, we discuss the purpose of this rule, the major provisions of the final rule, the context for the rulemaking, key changes from the proposal, the estimated CO
The purpose of this rule is to protect human health and the environment by reducing CO
Concurrent with this action, the EPA is also issuing a final rule that establishes CO
As with past rules under CAA section 111, this rule relies on proven technologies and measures to set achievable emission performance rates that will lead to cost-effective pollutant emission reductions, in this case CO
States will play a key role in ensuring that emission reductions are achieved at a reasonable cost. The experience of
This final rule is a significant step forward in implementing the President's Climate Action Plan.
Nationwide, by 2030, this final CAA section 111(d) existing source rule will achieve CO
The EPA projects that these reductions, along with reductions in other air pollutants resulting directly from this rule, will result in net climate and health benefits of $25 billion to $45 billion in 2030. At the same time, coal and natural gas will remain the two leading sources of electricity generation in the U.S., with coal providing about 27 percent of the projected generation and natural gas providing about 33 percent of the projected generation.
a.
While our consideration of public input and additional information has led to notable revisions from the emission guidelines we proposed in June 2014, the proposed guidelines remain the foundation of this final rule. These final guidelines build on the progress already underway to reduce the carbon intensity of power generation in the U.S., especially through the lowest carbon-intensive technologies, while reflecting the unique interconnected and interdependent system within which EGUs operate. Thus, the BSER, as determined in these guidelines, incorporates a range of CO
Equally important, these guidelines offer states and owners and operators of EGUs broad flexibility and latitude in complying with their obligations. Because affordability and electricity system reliability are of paramount importance, the rule provides states and utilities with time for planning and investment, which is instrumental to ensuring both manageable costs and system reliability, as well as to facilitating clean energy innovation. The final rule continues to express the CO
b.
States will be able to address the economic interests of their utilities and ratepayers by using the flexibilities in this final action to reduce costs to consumers, minimize stranded assets, and spur private investments in RE and EE technologies and businesses. They may also, if they choose, work with other states on multi-state approaches that reflect the regional structure of electricity operating systems that exists in most parts of the country and is critical to ensuring a reliable supply of affordable energy. The final rule gives states the flexibility to implement a broad range of approaches that recognize that the utility power sector is made up of a diverse range of companies of various sizes that own and operate fossil fuel-fired EGUs, including vertically integrated companies in regulated markets, independent power producers, rural cooperatives and municipally-owned utilities, some of which are likely to have more direct access than others to certain types of GHG emission reduction opportunities, but all of which have a wide range of opportunities to achieve reductions or acquire clean generation.
Again, with features that facilitate mass-based and/or interstate trading, the final guidelines also empower affected EGUs to pursue a broad range of choices for compliance and for integrating compliance action with the full range of their investments and operations.
c.
In this final action, the EPA is setting emission performance rates, phased in over the period from 2022 through 2030, for two subcategories of affected fossil fuel-fired EGUs—fossil fuel-fired electric utility steam-generating units and stationary combustion turbines. These rates, applied to each state's particular mix of fossil fuel-fired EGUs, generate the state's carbon intensity goal for 2030 (and interim rates for the period 2022-2029). Each state will determine whether to apply these to each affected EGU or to take an alternative approach and meet either an equivalent statewide rate-based goal or statewide mass-based goal. The EPA does not prescribe how a state must meet the emission guidelines, but, if a state chooses to take the path of meeting a state goal, these final guidelines identify the methods that a state can or, in some cases, must use to demonstrate that the combination of measures and standards that the state adopts meets its state-level CO
CAA section 111(d) creates a partnership between the EPA and the states under which the EPA establishes emission guidelines and the states take the lead on implementing them by establishing emission standards or creating plans that are consistent with the EPA emission guidelines. The EPA recognizes that each state has differing policy considerations—including varying regional emission reduction opportunities and existing state programs and measures—and that the characteristics of the electricity system in each state (
To facilitate the state planning process, this final rule establishes guidelines for the development, submittal, and implementation of state plans. The final rule describes the components of a state plan, the additional latitude states have in developing strategies to meet the emission guidelines, and the options they have in the timing of submittal of their plans. This final rule also gives states considerable flexibility with respect to the timeframes for plan development and implementation, as well as the choice of emission reduction measures. The final rule provides up to fifteen years for full implementation of all emission reduction measures, with incremental steps for planning and then for demonstration of CO
d.
As the EPA has done in making BSER determinations in previous CAA section 111 rulemakings, for this final BSER determination, the agency considered the types of strategies that states and owners and operators of EGUs are already employing to reduce the covered pollutant (in this case, CO
In so doing, as has always been the case, our considerations were not limited solely to specific technologies or equipment in hypothetical operation; rather, our analysis encompassed the full range of operational practices, limitations, constraints and opportunities that bear upon EGUs' emission performance, and which reflect the unique interconnected and interdependent operations of EGUs and the overall electricity grid.
In this final action, the agency has determined that the BSER comprises the first three of the four proposed “building blocks,” with certain refinements to the three building blocks.
The three building blocks are:
1. Improving heat rate at affected coal-fired steam EGUs.
2. Substituting increased generation from lower-emitting existing natural gas combined cycle units for generation from higher-emitting affected steam generating units.
3. Substituting increased generation from new zero-emitting renewable energy generating capacity for generation from affected fossil fuel-fired generating units.
These three building blocks are approaches that are available to all affected EGUs, either through direct investment or operational shifts or through emissions trading where states, which must establish emission standards for affected EGUs, do so by incorporating emissions trading.
e.
(1)
In this action, the EPA is establishing CO
Affected EGUs, individually, in aggregate, or in combination with other measures undertaken by the state, must achieve the equivalent of the CO
(2)
The best system of emission reduction includes both the measures for reducing CO
f.
In this action, the EPA is establishing final guidelines for states to follow in developing, submitting and implementing their plans. In developing plans, states will need to choose the type of plan they will develop. They will also need to include required plan components in their plan submittals, meet plan submittal deadlines, achieve the required CO
(1)
To comply with these emission guidelines, a state will have to ensure, through its plan, that the emission standards it establishes for its sources individually, in aggregate, or in combination with other measures undertaken by the state, represent the equivalent of the subcategory-specific CO
First, in the final rule, states may establish emission standards for their affected EGUs that mirror the uniform emission performance rates for the two subcategories of sources included in this final rule. They may also pursue alternative approaches that adopt emission standards that meet the
The second major set of options provided in the final rule includes the types of measures states may rely on through the state plans. A state will be able to choose to establish emission standards for its affected EGUs sufficient to meet the requisite performance rates or state goal, thus placing all of the requirements directly on its affected EGUs, which we refer to as the “emission standards approach.” Alternatively, a state can adopt a “state measures approach,” which would result in the affected EGUs meeting the statewide mass-based goal by allowing a state to rely upon state-enforceable measures on entities other than affected EGUs, in conjunction with any federally enforceable emission standards the state chooses to impose on affected EGUs. With a state measures approach, the plan must also include a contingent backstop of federally enforceable emission standards for affected EGUs that fully meet the emission guidelines and that would be triggered if the plan failed to achieve the required emission reductions on schedule. A state would have the option of basing its backstop emission standards on the model rule, which focuses on the use of emissions trading as the core mechanism and which the EPA is proposing today. A state that adopts a state measures approach must use its mass CO
The final rule requires that the state plan submittal include a timeline with all of the programmatic plan milestone steps the state will take between the time of the state plan submittal and the year 2022 to ensure that the plan is effective as of 2022. States must submit a report to the EPA in 2021 that demonstrates that the state has met the programmatic plan milestone steps that the state indicated it would take during the period from the submittal of the final plan through the end of 2020, and that the state is on track to implement the approved state plan as of January 1, 2022.
The plan must also include a process for reporting on plan implementation, progress toward achieving CO
Existing state programs can be aligned with the various state plan options further described in Section VIII. A state plan that uses one of the finalized model rules, which the EPA is proposing concurrently with this action, could be presumptively approvable if the state plan meets all applicable requirements.
State plan approaches and plan guidelines are explained further in section VIII of this preamble.
(2)
The EPA's implementing regulations provide certain basic elements required for state plans submitted pursuant to CAA section 111(d).
All state plans must include the following components:
• Description of the plan
• Applicability of state plans to affected EGUs
• Demonstration that the plan submittal is projected to achieve the state's CO
• Monitoring, reporting and recordkeeping requirements for affected EGUs
• State recordkeeping and reporting requirements
• Public participation and certification of hearing on state plan
• Supporting documentation
Also, in submitting state plans, states must provide documentation demonstrating that they have considered electric system reliability in developing their plans.
Further, in this final rule, the EPA is requiring states to demonstrate how they are meaningfully engaging all stakeholders, including workers and low-income communities, communities of color, and indigenous populations living near power plants and otherwise potentially affected by the state's plan. In their plan submittals, states must describe their engagement with their stakeholders, including their most vulnerable communities. The participation of these communities, along with that of ratepayers and the public, can be expected to help states ensure that state plans maintain the affordability of electricity for all and preserve and expand jobs and job opportunities as they move forward to develop and implement their plans.
State plan submittals using the emission standards approach must also include:
• Identification of each affected EGU; identification of federally enforceable emission standards for the affected EGUs; and monitoring, recordkeeping and reporting requirements.
• Demonstrations that each emission standard will result in reductions that are quantifiable, non-duplicative, permanent, verifiable, and enforceable.
State plan submittals using the state measures approach must also include:
• Identification of each affected EGU; identification of federally enforceable emission standards for affected EGUs (if applicable); identification of backstop of
• Identification of each state measure and demonstration that each state measure will result in reductions that are quantifiable, non-duplicative, permanent, verifiable, and enforceable.
In addition to these requirements, each state plan must follow the EPA implementing regulations at 40 CFR 60.23.
(3)
Because of the compelling need for actions to begin the steps necessary to reduce GHG emissions from EGUs, the EPA proposed that states submit their plans within 13 months of the date of this final rule and that reductions begin in 2020. In light of the comments received and in order to provide maximum flexibility to states while still taking timely action to reduce CO
If the initial submittal includes those components and if the EPA does not notify the state that the initial submittal does not contain the required components, then, within 90 days of the submittal, the extension of time to submit a final plan will be deemed granted. A state will then have until no later than September 6, 2018, to submit a final plan. The EPA will also be working with states during the period after they make their initial submittals and provide states with any necessary information and assistance during the 90-day period. Further, states participating in a multi-state plan may submit a single joint plan on behalf of all of the participating states.
States and tribes that do not have any affected EGUs in their jurisdictional boundaries may provide emission rate credits (ERCs) to adjust CO
Following submission of final plans, the EPA will review plan submittals for approvability. Given a similar timeline accorded under section 110 of the CAA, and the diverse approaches states may take to meet the CO
(4)
The EPA recognizes that the measures states and utilities have been and will be taking to reduce CO
The EPA recognizes that successfully achieving reductions by 2022 will be facilitated by actions and investments that yield CO
In addition, to encourage early investments in RE and demand-side EE, the EPA is establishing the CEIP. Through this program, detailed in section VIII.B of this preamble, states will have the opportunity to award allowances and ERCs to qualified providers that make early investments in RE, as well as in demand-side EE programs implemented in low-income communities. Those states that take advantage of this option will be eligible to receive from the EPA matching allowances or ERCs, up to a total for all states that represents the equivalent of 300 million short tons of CO
The EPA will address design and implementation details of the CEIP in a subsequent action. Prior to doing so, the EPA will engage with states, utilities and other stakeholders to gather information regarding their interests and priorities with regard to implementation of the CEIP.
The CEIP can play an important role in supporting one of the critical policy benefits of this rule. The incentives and market signal generated by the CEIP can help sustain the momentum toward greater RE investment in the period between now and 2022 so as to offset any dampening effects that might be created by setting the period for mandatory reductions to begin in 2022, two years later than at proposal.
(5)
Climate change is an environmental justice issue. Low-income communities and communities of color already overburdened by pollution are disproportionately affected by climate change and are less resilient than others to adapt to or recover from climate-change impacts. While this rule will provide broad benefits to communities across the nation by reducing GHG emissions, it will be particularly beneficial to populations that are disproportionately vulnerable to the impacts of climate change and air pollution.
Conventional pollutants emitted by power plants, such as particulate matter (PM), SO
While pollution will be cut from power plants overall, there may be some relatively small number of coal-fired plants whose operation and corresponding emissions increase as energy providers balance energy production across their fleets to comply with state plans. In addition, a number of the highest-efficiency natural gas-fired units are also expected to increase operations, but they have correspondingly low carbon emissions and are also characterized by low emissions of the conventional pollutants that contribute to adverse health effects in nearby communities and regionally. The EPA strongly encourages states to evaluate the effects of their plans on vulnerable communities and to take the steps necessary to ensure that all communities benefit from the implementation of this rule. In order to identify whether state plans are causing any adverse impacts on overburdened communities, mindful that substantial overall reductions, nevertheless, may be accompanied by potential localized increases, the EPA intends to perform an assessment of the implementation of this rule to determine whether it and other air quality rules are leading to improved air quality in all areas or whether there are localized impacts that need to be addressed.
Effective engagement between states and affected communities is critical to the development of state plans. The EPA encourages states to identify communities that may be currently experiencing adverse, disproportionate impacts of climate change and air pollution, how state plan designs may affect them, and how to most effectively reach out to them. This final rule requires that states include in their initial submittals a description of how they engaged with vulnerable communities as they developed their initial submittals, as well as the means by which they intend to involve communities and other stakeholders as they develop their final plans. The EPA will provide training and other resources for states and communities to facilitate meaningful engagement.
In addition to the benefits for vulnerable communities from reducing climate change impacts and effects of conventional pollutant emissions, this rule will also help communities by moving the utility industry toward cleaner generation and greater EE. The federal government is committed to ensuring that all communities share in these benefits.
The EPA also encourages states to consider how they may incorporate approaches already used by other states to help low-income communities share in the investments in infrastructure, job creation, and other benefits that RE and demand-side EE programs provide, have access to financial assistance programs, and minimize any adverse impacts that their plans could have on communities. To help support states in taking concrete actions that provide economic development, job and electricity bill-cutting benefits to low-income communities directly, the EPA has designed the CEIP specifically to target the incentives it creates on investments that benefit low-income communities.
Community and environmental justice considerations are discussed further in section IX of this preamble.
(6)
In addition, the EPA encourages states in designing their state plans to consider the effects of their plans on employment and overall economic development to assure that the opportunities for economic growth and jobs that the plans offer are realized. To the extent possible, states should try to assure that communities that can be expected to experience job losses can also take advantage of the opportunities for job growth or otherwise transition to healthy, sustainable economic growth. The President has proposed the POWER+ Plan to help communities impacted by power sector transition. The POWER+ plan invests in workers and jobs, addresses important legacy costs in coal country, and drives
(7)
In no small part thanks to the comments we received and our extensive consultation with key agencies responsible for reliability, including FERC and DOE, among others, along with EPA's longstanding principles in setting emission standards for the utility power sector, these guidelines reflect the paramount importance of ensuring electric system reliability. The input we received on this issue focused heavily on the extent of the reductions required at the beginning of the interim period, proposed as 2020. We are addressing these concerns in large part by moving the beginning of the period for mandatory reductions under the program from 2020 to 2022 and significantly adjusting the interim goals so that they provide a less abrupt initial reduction expectation. This, in turn, will provide states and utilities with a great deal more latitude in determining their emission reduction trajectories over the interim period. As a result, there will be more time for planning, consultation and decision making in the formulation of state plans and in EGUs' choice of compliance strategies, all within the existing extensive structure of energy planning at the state and regional levels. These adjustments in the interim goals are supported by the information in the record concerning the time needed to develop and implement reductions under the BSER. In addition, the various forms of flexibility retained and enhanced in this final rule, including opportunities for trading within and between states, and other multi-state compliance approaches, will further support electric system reliability.
The final guidelines address electric system reliability in several additional important ways. Numerous commenters urged us to include, as part of the plan development or approval process, input from review by energy regulatory agencies and reliability entities. In the final rule, we are requiring that each state demonstrate in its final state plan submittal that it has considered reliability issues in developing its plan. Second, we recognize that issues may arise during the implementation of the guidelines that may warrant adjustments to a state's plan in order to maintain electric system reliability. The final guidelines make clear that states have the ability to propose amendments to approved plans in the event that unanticipated and significant electric system reliability challenges arise and compel affected EGUs to generate at levels that conflict with their compliance obligations under those plans.
As a final element of reliability assurance, the rule also provides for a reliability safety valve for individual sources where there is a conflict between the requirements the state plan imposes on a specific affected EGU and the maintenance of electric system reliability in the face of an extraordinary and unanticipated event that presents substantial reliability concerns.
We anticipate that these situations will be extremely rare because the states have the flexibility to craft requirements for their EGUs that will provide long averaging periods and/or compliance mechanisms, such as trading, whose inherent flexibility will make it unlikely that an individual unit will find itself in this kind of situation. As one example, under compliance regimes that allow individual EGUs to establish compliance through the acquisition and holding of allowances or ERCs equal to their emissions, an EGU's need to continue to operate—and emit—for the purposes of ensuring system reliability will not put the EGU into non-compliance, provided, of course, it obtains the needed allowances or credits in a timely fashion. We, nevertheless, agree with many commenters that it is prudent to provide an electric system reliability safety valve as a precaution.
Finally, the EPA, DOE and FERC have agreed to coordinate their efforts, at the federal level, to help ensure continued reliable electricity generation and transmission during the implementation of the final rule. The three agencies have set out a memorandum that reflects their joint understanding of how they will work together to monitor implementation, share information, and to resolve any difficulties that may be encountered.
As a result of the many features of this final rule that provide states and affected EGUs with meaningful time and decision making latitude, we believe that the comprehensive safeguards already in place in the U.S. to ensure electric system reliability will continue to operate effectively as affected EGUs reduce their CO
(8)
To provide states, U.S. territories, tribes, utilities, communities, and other interested stakeholders with understanding about the rule requirements, and to provide efficiencies where possible and reduce the cost and administrative burden, the EPA will continue to work with states, tribes, territories, and stakeholders to provide information and address questions about the final rule. Outreach will include opportunities for states and tribes to participate in briefings, teleconferences, and meetings about the final rule. The EPA's ten regional offices will continue to be the entry point for states, tribes and territories to ask technical and policy questions. The agency will host (or partner with appropriate groups to co-host) a number of webinars about various components of the final rule; these webinars are planned for the first two months after the final rule is issued. The EPA will also offer consultations with tribal governments. The EPA will continue outreach throughout the plan development and submittal process. The EPA will use information from this outreach process to inform the training and other tools that will be of most use to the state, tribes, and territories that are implementing the final rule.
The EPA has worked with communities, states, tribes and relevant associations to develop an extensive training plan that will continue in the months after the Clean Power Plan is finalized. The EPA has assembled resources from a variety of sources to create a comprehensive training curriculum for those implementing this rule. Recorded presentations from the EPA, DOE and other federal entities will be available for communities, states, and others involved in composing and participating in the development of state plans. This curriculum is available online at EPA's Air Pollution Training Institute.
The EPA also expects to issue guidance on specific topics. As guidance documents, tools, templates and other resources become available, the EPA, in consultation with DOE and other federal agencies, will continue to make these resources available via a dedicated Web site.
We intend to continue to work actively with states and tribes, as appropriate, to provide information and technical support that will be helpful to
Additional detail on aspects of the final rule is included in several technical support documents (TSDs) and memoranda that are available in the rulemaking docket.
a.
To achieve these objectives, the June 2014 proposal featured several important elements: The building block approach for the BSER; state-specific, rather than source-specific, goals; a 10-year interim goal that could be met “on average” over the 10-year period between 2020 and 2029; and a “portfolio” option for state plans. These features were intended either to capture, in the emission guidelines, emission reduction measures already in widespread use or to maximize the range of choices that states and utilities could select in order to achieve their emission limitations at low cost while ensuring electric system reliability. In this final rule, we are retaining the key design elements of the proposal and making certain adjustments to respond to a variety of very constructive comments on ways that will implement the CAA section 111(d) requirements efficiently and effectively.
The building block approach is a key feature of the proposal that we are retaining in the final rule, but have refined to include only the first three building blocks and to reflect implementation of the measures encompassed in the building blocks on a broad regional grid-level. In the proposal, we expressed the emission limitation requirements reflecting the BSER in terms of the state goals in order to provide states with maximum flexibility and latitude. We viewed this as an important feature because each state has its own energy profile and state-specific policies and needs relative to the production and use of electricity. In the final rule, we extend that flexibility significantly in direct response to comments from states and utilities. The final rule establishes source-level emission performance rates for the source subcategories, while retaining state-level rate- and mass-based goals. One of the key messages conveyed by state and utility commenters was that the final rule should make it easier for states to adopt mass-based programs and for utilities accustomed to operating across broad multi-state grids to be able to avail themselves of more “ready-made” emissions trading regimes. The inclusion of both of these new features—mass-based state goals in addition to rate-based goals, and source-level emission performance rates for the two subcategories of sources—is intended to make it easier for states and utilities to achieve these outcomes. In fact, these additions, together with the model rules and federal plan being proposed concurrently with this rule, should demonstrate the relative ease with which states can adopt mass-based trading programs, including interstate mass-based programs that lend themselves to the kind of interstate compliance strategies so well suited for integration with the current interstate operations of the overall utility grid.
Many stakeholders conveyed to the EPA that the proposal's interim goals for the 2020-2029 period were designed in a way that defeated the EPA's objective of allowing states and utilities to shape their emission reduction trajectories. They pointed out that, in many cases, the timing and stringency of the states' interim goals could require actions that could result in high costs, threaten electric system reliability or hinder the deployment of renewable technology. In response, the EPA has revised the interim goals in two critical ways. First, the period for mandatory reductions begin in 2022 rather than 2020; second, in keeping with the BSER, emission reduction requirements are phased in more gradually over the interim period. These changes will allow states and utilities to delineate their own emission reduction trajectories so as to minimize costs and foster broader deployment of RE technologies. The value of these changes is demonstrated by our analysis of the final rule, which shows lower program costs, especially in the early years of the interim period, and greater RE deployment, relative to the analysis of the proposed rule. At the same time, this re-design of the interim goals, together with refinements we have made to state plan requirements and the inclusion of a reliability safety valve, provide states, utilities and other entities with the ability to continue to guarantee system reliability.
b.
The insights gained from public comments contributed to the development of final emission guidelines that build on the proposal and the alternatives on which we sought comment. The modifications incorporated in the final guidelines are directly responsive to the comments we received from the many and diverse stakeholders. The improved guidelines reflect information and ideas that states and utilities provided to us about both the best approach to establishing CO
c.
We provide summary explanations in the following paragraphs and more detailed explanations of all of these changes in later sections of this preamble and associated documents.
(1)
The proposal's mandatory emission reduction period beginning in 2020 and the trajectory of emission reduction requirements in the interim period were both the subjects of significant comment. Earlier this year, FERC conducted a series of technical conferences comprising one national session and three regional sessions. The information provided by workshop participants echoed much of the material that had been submitted to the comment record for this rulemaking. On May 15, 2015, the FERC Commissioners, drawing upon information highlighted at the technical conferences, transmitted to the EPA some suggestions for the final rule. In addition, via comments, states, utilities, and reliability entities asked us to ensure adequate time for them to implement strategies to achieve CO
The final guidelines' approach to the interim emission performance rates is the result of the application of the measures constituting the BSER in a more gradual way, reflecting stakeholder comments and information about the appropriate period of time over which those measures can be deployed consistent with the BSER factors of cost and feasibility. In addition to facilitating reliable system operations, these changes provide states and utilities with the latitude to consider a broader range of options to achieve the required reductions while addressing concerns about ratepayer impacts and stranded assets.
(2)
Commenters urged the EPA to confine its BSER determination to actions that involve what they characterized as more “traditional” generation. While some stakeholders recognized demand-side EE as being an integral part of the electricity system, with many of the characteristics of more traditional generating resources, other stakeholders did not. As explained in section V.B.3.c.(8) below, our traditional interpretation and implementation of CAA section 111 has allowed regulated entities to produce as much of a particular good as they desire, provided that they do so through an appropriately clean (or low-emitting) process. While building blocks 1, 2, and 3 fall squarely within this paradigm, the proposed building block 4 does not. In view of this, since the BSER must serve as the foundation of the emission guidelines, the EPA has not included demand-side EE as part of the final BSER determination. Thus, neither the final guidelines' BSER determination nor the emission performance rates for the two subcategories of affected EGUs take into account demand-side EE. However, many commenters also urged the EPA to allow states and sources to rely on demand-side EE as an element of their compliance strategies, as demand-side EE is treated as functionally interchangeable with other forms of generation for planning and operational purposes, as EE measures are in widespread use across the country and provide energy savings that reduce emissions, lower electric bills, and lead to positive investments and job creation. We agree, and the final guidelines provide ample latitude for states and utilities to rely on demand-side EE in
In response to stakeholder comments on the first three building blocks and considerable data in the record, the EPA has made refinements to the building blocks, and these are reflected in the final BSER. Refinements include adoption of a modified approach to quantification of the RE component, exclusion of the proposed nuclear generation components, and adoption of a consistent regionalized approach to quantification of all three building blocks. The agency also recognizes the important functional relationship between the period of time over which measures are deployed and the stringency of emission limitations those measures can achieve practically and at reasonable cost. Therefore, the final BSER also reflects adjustments to the stringency of the building blocks, after consideration of more and less stringent levels, and refinements to the timeframe over which reductions must be achieved. Sections V.C through V.E of this preamble provide further information on the refinements made to the building blocks and the rationale for doing so.
Commenters pointed out—and practical experience confirms—what is widely known: That the utility power sector operates over regional interconnections that are not constrained by state borders. Across a variety of issues raised in the proposal, many commenters urged that the EPA take that reality into account in developing this final rule. Consequently, the BSER determination itself (as well as a number of new compliance features included in this final rule) and the resulting subcategory-specific emission performance rates take into account the grid-level operations of the source category.
The final guidelines' BSER determination also takes into account recent reductions in the cost of clean energy technology, as well as projections of continuing cost reductions, and continuing increases in RE deployment. We also updated the underlying analysis with the most recent Energy Information Administration (EIA) projections that show lower growth in electricity demand between 2020 and 2030 than previously projected. In keeping with these recent EIA projections, we expect the final guidelines will be more conducive to compliance, consistent with a strategy that allows for the cleanest power generation and greater CO
(3)
Some stakeholders commented that the proposal's approach of expressing the BSER in terms of state-specific goals deviated from the requirements of CAA section 111 and from previous new source performance standards (NSPS). The effect, they stated, was that the proposal created de facto emission standards for all affected EGUs but that these de facto standards varied widely depending on the state in which a given EGU happened to be located. Instead, these and other commenters stated, section 111 requires that EPA establish the BSER specifically for affected sources, rather than by means of merely setting state-specific goals, and that these standards be uniform. Still other commenters observed that the effect of the approach taken in the proposal of applying the BSER to each state's fleet was to put a greater burden of reductions on lower-emitting or less carbon-intensive states and a lesser emission reduction burden on sources and states that were higher-emitting or more carbon-intensive. This, they argued, was both inequitable and at odds with the way in which NSPS have been applied in the past, where the higher-emitting sources have made the greater and more cost-effective reductions, while lower-emitting sources, whose reduction opportunities tend to be less cost-effective, have been required to make fewer reductions to meet the applicable standard.
At the same time, state and utility commenters expressed concern that relying on state-specific goals and state-by-state planning could introduce complexity into the otherwise seamless integrated operation of affected EGUs across the multi-state grids on which system operators, states and utilities currently rely and intend to continue to rely. Accordingly, they recommended that the final guidelines facilitate emissions trading, in particular interstate trading, which would enable EGU operators to integrate compliance with CO
The EPA carefully considered these comments and while we believe that the approach we took at proposal was well-founded and reflected a number of important considerations, we have concluded that there is a way to address these concerns while expanding upon the advantages offered by the proposal. Accordingly, the final guidelines establish uniform rates for the two subcategories of sources—an approach that is valuable for creating greater equity between and among utilities and states with widely varying emission levels and for expanding the flexibility of the program, especially in ways that have been identified as important to utilities and states. Specifically, the final guidelines express the BSER by means of performance-based CO
This approach rectifies what would have been an inefficient, unintended outcome of putting the greater reduction burden on lower-emitting sources and states while exempting higher-emitting sources and states. Expressing the BSER by means of these rates also augments the range of options for both states and EGUs for securing needed flexibility. Inclusion of state goals creates latitude for states as to how they will meet the guidelines. States also may meet the guideline requirements by adopting the CO
During the outreach process and through comments, a number of state officials and other stakeholders expressed concern that the EPA's approach at proposal necessitated or represented a significant intrusion into state-level energy policy-making, drawing the EPA well beyond the bounds of its CAA authority and expertise. In fact, these final guidelines are entirely respectful of the EPA's responsibility and authority to regulate sources of air pollution. Instead, by establishing and operating through uniform performance rates for the two subcategories of sources that can be applied by states at the individual source level and that can readily be implemented through emission standards that incorporate emissions trading, these final guidelines align with the approach Congress and the EPA have consistently taken to regulating emissions from this and other industrial sectors, namely setting source-level, source category-wide standards that individual sources can meet through a variety of technologies and measures.
We emphasize, at the same time, that while the final guidelines express the BSER by means of source-level CO
(4)
Commenters expressed support for the objectives served by the “portfolio” option in the state plan approaches included at proposal, but many raised concerns about its legality, with respect, in particular, to the CAA's enforceability requirements. Some of these commenters identified a “state commitment approach” with backstop measures as a variation of the “portfolio” approach that would retain the benefits of the “portfolio” approach while resolving legal and enforceability concerns. In this final rule, in response to stakeholder comments on the portfolio approach and alternative approaches, the EPA is finalizing two approaches: A source-based “emission standards” approach, and a “state measures” approach. Through the latter, states may adopt a set of policies and programs, which would not be federally enforceable, except that any standards imposed on affected EGUs would be federally enforceable. In addition, states would be required to include federally enforceable backstop measures applicable to each affected EGU in the event that the measures included in the state plan failed to achieve the state plan's emissions reduction trajectory. Under these guidelines, states can implement the BSER through standards of performance incorporating the uniform performance rates or alternative but in the aggregate equivalent rates, or they can adopt plans that achieve in aggregate the equivalent of the subcategory-specific CO
(5)
Many state and utility commenters supported the use of mass-based and rate-based emission trading programs in state plans, including interstate emission trading programs, and either pointed out obstacles to establishing such programs or suggested approaches that would enhance states' and utilities' ability to create and participate in such programs.
Through a combination of features retained from the proposal and changes made to the proposal, these final guidelines provide states and utilities with a panoply of tools that greatly facilitate their putting in place and participating in emissions trading programs. These include: (1) Expressing BSER in uniform emission performance rates that states may rely on in setting emission standards for affected EGUs such that EGUs operating under such standards readily qualify to trade with affected EGUs in states that adopt the same approach, (2) promulgating state mass goals so that states can move quickly to establish mass-based programs such that their affected EGUs readily qualify to trade with affected EGUs in states that adopt the same approach, and (3) providing EPA resources and capacity to create a tracking system to support state emissions trading programs.
(6)
Stakeholders, particularly states, provided compelling information establishing that it could take longer than the agency initially anticipated for the states to develop and submit their required plans. While the approach at proposal reflected the EPA's conclusion that it was essential to the environmental and economic purposes of this rulemaking that utilities and states establish the path towards emissions reductions as early as possible, we recognize commenters' concerns. To strike the proper balance, the EPA has developed a revised state plan submittal schedule. For states that cannot submit a final plan by September 6, 2016, the EPA is requiring those states to make an initial submittal by that date to assure that states begin to address the urgent needs for reductions quickly, and is providing until September 6, 2018, for states to submit a final plan, if an extension until that date is justified, to address the concern that a submitting state needs more time to develop comprehensive plans that reflect the full range of the state's and its stakeholders' interests.
(7)
Many commenters supported providing incentives for states and utilities to deploy CO
The CEIP is designed to incentivize investment in certain RE and demand-side EE projects that commence construction, in the case of RE, or commence construction, in the case of demand-side EE, following the submission of a final state plan to the EPA, or after September 6, 2018, for states that choose not to submit a final state plan by that date, and that generate MWh (RE) or reduce end-use energy demand (EE) during 2020 and/or 2021. State participation in the program is optional.
Under the CEIP, a state may set aside allowances from the CO
For a state to be eligible for a matching award of allowances or ERCs from the EPA, it must demonstrate that it will award allowances or ERCs only to “eligible” projects. These are projects that:
• Are located in or benefit a state that has submitted a final state plan that includes requirements establishing its participation in the CEIP;
• Are implemented following the submission of a final state plan to the EPA, or after September 6, 2018, for a state that chooses not to submit a complete state plan by that date;
• For RE: Generate metered MWh from any type of wind or solar resources;
• For EE: Result in quantified and verified electricity savings (MWh) through demand-side EE implemented in low-income communities; and
• Generate or save MWh in 2020 and/or 2021.
The following provisions outline how a state may award early action ERCs and allowances to eligible projects, and how the EPA will provide matching ERCs or allowances to states.
• For RE projects that generate metered MWh from any type of wind or solar resources: For every two MWh generated, the project will receive one early action ERC (or the equivalent number of allowances) from the state, and the EPA will provide one matching ERC (or the equivalent number of allowances) to the state to award to the project.
• For EE projects implemented in low-income communities: For every two MWh in end-use demand savings achieved, the project will receive two early action ERCs (or the equivalent number of allowances) from the state, and the EPA will provide two matching ERCs (or the equivalent number of allowances) to the state to award to the project.
Early action allowances or ERCs awarded by the state, and matching allowances or ERCs awarded by the EPA pursuant to the CEIP, may be used for compliance by an affected EGU with its emission standards and are fully transferrable prior to such use.
The EPA discusses the CEIP in the proposed federal plan rule and will address design and implementation details of the CEIP in a subsequent action. Prior to doing so, the EPA will engage with states, utilities and other stakeholders to gather information regarding their interests and priorities with regard to implementation of the CEIP.
(8)
A number of commenters stressed the importance of final guidelines that addressed the need to ensure that EGUs could meet their emission reduction requirements without being compelled to take actions that would undermine electric system reliability. As noted above, the EPA has consulted extensively with federal, regional and state energy agencies, utilities and many others about reliability concerns and ways to address them. The final guidelines support electric system reliability in a number of ways, some inherent in the improvements made in the program's design and some through specific provisions we have included in the final rule. Most important are the two key changes we made to the interim goal: Establishing 2022, instead of 2020, as the period for mandatory emission reductions begin and phasing in, over the 8-year period, emission performance rates such that the level of stringency of the emission performance rates in 2022-2024 is significantly less than that for the years 2028 and 2029. Since states and utilities need only to meet their interim goal “on average” over the 8-year period, these changes provide them with a great deal of latitude in determining for themselves their emission reduction trajectory—and they have additional time to do so. As a result, the final guidelines provide the ingredients that commenters, reliability entities and expert agencies told the EPA were essential to ensuring electric system reliability: Time and flexibility sufficient to allow for planning, implementation and the integration of actions needed to address reliability while achieving the required emissions reductions.
In addition, the final guidelines add a requirement, based on substantial input from experts in the energy field, for states to demonstrate that they have considered electric system reliability in developing their state plans. The final rule also offers additional opportunities that support electric system reliability, including opportunities for trading within and between states. The final guidelines also make clear that states can adjust their plans in the event that reliability challenges arise that need to be remedied by amending the state plan. In addition, the final rule includes a reliability safety valve to address situations where, because of an unanticipated catastrophic event, there is a conflict between the requirements imposed on an affected unit and the maintenance of reliability.
(9)
Some commenters brought to our attention the concerns of workers, their families and communities, particularly in coal-producing regions and states, that the ongoing shift toward lower-carbon electricity generation that the final rule reflects will cause harm to communities that are dependent on coal. Others had concerns about whether new jobs created as a result of actions taken pursuant to the final rule will allow for overall economic development. In the final rule, the EPA encourages states, in designing their state plans, to consider the effects of their plans on employment and overall economic development to assure that the opportunities for economic growth and jobs that the plans offer are manifest. We also identify federal programs, including the multi-agency Partnerships for Opportunity and Workforce and Economic Revitalization (POWER) Initiative.
(10)
Many community leaders, environmental justice advocates, faith-based organizations and others commented that the benefits of this rule must be shared broadly across society and that undue burdens should not be imposed on low-income ratepayers. We agree. The federal government is taking significant steps to help low-income families and individuals gain access to RE and demand-side EE through new initiatives involving, for example, increasing solar energy systems in federally subsidized homes and supporting solar systems for others with low incomes. The final rule ensures that bill-lowering measures such as demand-side EE continue to be a major
a.
b.
The utility power sector is unlike other industrial sectors. In other sectors, sources effectively operate independently and on a local-site scale, with control of their physical operations resting in the hands of their respective owners and operators. Pollution control standards, which focus on each source in a non-utility industrial source category, have reflected the standalone character of individual source investment decision-making and operations.
In stark contrast, the utility power sector comprises a unique system of electricity resources, including the EGUs affected under these guidelines, that operate in a complex and interconnected grid where electricity generally flows freely (
The approach we take in the final guidelines—both in the way we defined the BSER and established the resulting emission performance rates, and in the ranges of options we created for states
In this integrated system, numerous entities have both the capability and the responsibility to maintain a reliable electric system. FERC, DOE, state public utility commissions, ISOs, RTOs, other planning authorities, and the North American Electric Reliability Corporation (NERC), all contribute to ensuring the reliability of the electric system in the U.S. Critical to this function are dispatch tools, applied primarily by RTOs, ISOs, and balancing authorities, that operate such that actions taken or costs incurred at one source directly affect or cause actions to occur at other sources. Generation, outages, and transmission changes in one part of the synchronous grid can affect the entire interconnected grid.
The uniqueness of the utility power sector inevitably affects the way in which environmental regulations are designed. When the EPA promulgates environmental regulations that affect the utility power sector, as we have done numerous times over the past four decades, we do so with the awareness of the importance of the efficient and continuous, uninterrupted operation of the interconnected electricity system in which EGUs participate. We also keep in mind the unique product that this interconnected system provides—electricity services—and the critical role of this sector to the U.S. economy and to the fundamental well-being of all Americans.
In the context of environmental regulation, Congress, the EPA and the states all have recognized—as we do in these final guidelines—that electricity production takes place, at least to some extent, interchangeably between and among multiple generation facilities and different types of generation. This is evidenced in the enactment or promulgation of pollution reduction programs, such as Title IV of the CAA, the NO
The way that power is produced, distributed and used in the U.S. is already changing as a result of advancements in innovative power sector technologies and in the availability and cost of low-carbon fuel, RE and demand-side EE technologies, as well as economic conditions. These changes are taking place at a time when the average age of the coal-fired generating fleet is approaching that at which utilities and states undertake significant new investments to address aging assets. In 2025, the average age of the coal-fired generating fleet is projected to be 49 years old, and 20 percent of those units would be more than 60 years old if they remain in operation at that time. Therefore, even in the absence of additional environmental regulation, states and utilities can be expected to be, and already are, making plans for and investing in the next generation of power production, simply because of the need to take account of the age of current assets and infrastructure. Historically, the industry has invested about $100 billion a year in capital improvements. These guidelines will help ensure that, as those necessary investments are being made, they are integrated with the need to address GHG pollution from the sector.
At the same time, owners/operators of affected EGUs are already pursuing the types of measures contemplated in this rule. Out of 404 entities identified as owners or operators of affected EGUs, representing ownership of 82 percent of the total capacity of the affected EGUs, 178 already own RE generating capacity in addition to fossil fuel-fired generating capacity. In fact, these entities already own aggregate amounts of RE generating capacity equal to 25 percent of the aggregate amounts of their affected EGU capacity.
The final guidelines are based on, and reinforce, the actions already being taken by states and utilities to upgrade aging electricity infrastructure with 21st century technologies. The guidelines will ensure that these trends continue in ways that are consistent with the long-term planning and investment processes already used in the utility power sector. This final rule provides flexibility for states to build upon their progress, and the progress of cities and towns, in addressing GHGs, and minimizes
Under the final guidelines, the EPA projects annual CO
Actions taken to comply with the final guidelines will reduce emissions of CO
Because of the range of choices available to states and the lack of
In summary, we estimate the total combined climate benefits and health co-benefits for the rate-based approach to be $3.5 to $4.6 billion in 2020, $18 to $28 billion in 2025, and $34 to $54 billion in 2030 (3 percent discount rate, 2011$). Total combined climate benefits and health co-benefits for the mass-based approach are estimated to be $5.3 to $8.1 billion in 2020, $19 to $29 billion in 2025, and $32 to $48 billion in 2030 (3 percent discount rate, 2011$). A summary of the emission reductions and monetized benefits estimated for this rule at all discount rates is provided in Tables 15 through 22 of this preamble.
The annual compliance costs are estimated using the Integrated Planning Model (IPM) and include demand-side EE program and participant costs as well as monitoring, reporting and recordkeeping costs. In 2020, total compliance costs of the final guidelines are approximately $2.5 billion (2011$) under the rate-based approach and $1.4 billion (2011$) under the mass-based approach. In 2025, total compliance costs of the final guidelines are approximately $1.0 billion (2011$) under the rate-based approach and $3.0 billion (2011$) under the mass-based approach. In 2030, total compliance costs of the final guidelines are approximately $8.4 billion (2011$) under the rate-based approach and $5.1 billion (2011$) under the mass-based approach.
The quantified net benefits (the difference between monetized benefits and compliance costs) in 2020 are estimated to range from $1.0 billion to $2.1 billion (2011$) using a 3 percent discount rate (model average) under the rate-based approach and from $3.9 billion to $6.7 billion (2011$) using a 3 percent discount rate (model average) under the mass-based approach. In 2025, the quantified net benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated to range from $17 billion to $27 billion (2011$) using a 3 percent discount rate (model average) under the rate-based approach and from $16 billion to $26 billion (2011$) using a 3 percent discount rate (model average) under the mass-based approach. In 2030, the quantified net benefits (the difference between monetized benefits and compliance costs) in 2030 are estimated to range from $26 billion to $45 billion (2011$) using a 3 percent discount rate (model average) under the rate-based approach and from $26 billion to $43 billion (2011$) using a 3 percent discount rate (model average) under the mass-based approach.
There are additional important benefits that the EPA could not monetize. Due to current data and modeling limitations, our estimates of the benefits from reducing CO
We project employment gains and losses relative to base case for different types of labor, including construction, plant operation and maintenance, coal and natural gas production, and demand-side EE. In 2030, we project a net decrease in job-years of about 31,000 under the rate-based approach and 34,000 under the mass-based approach
Based upon the foregoing, it is clear that the monetized benefits of this rule are substantial and far outweigh the costs.
This final rule establishes the EPA's emission guidelines for states to follow in developing plans to reduce CO
We note that this rulemaking is being promulgated concurrently with two related actions in this issue of the
In this section, we discuss climate change impacts from GHG emissions, both on public health and public welfare. We also present information about GHG emissions from fossil fuel-fired EGUs, the challenges associated with controlling carbon dioxide emissions, the uniqueness of the utility power sector, and recent and continuing trends and transitions in the utility power sector. In addition, we briefly describe CAA regulations for power plants, provide highlights of Congressional awareness of climate change and international agreements and actions, and summarize statutory and regulatory requirements relevant to this rulemaking. In addition, we provide background information on the EPA's June 18, 2014 Clean Power Plan proposal, the November 4, 2014 supplemental proposal, and other actions associated with this rulemaking,
According to the National Research Council, “Emissions of CO
In 2009, based on a large body of robust and compelling scientific evidence, the EPA Administrator issued the Endangerment Finding under CAA section 202(a)(1).
Climate change caused by human emissions of GHGs threatens the health of Americans in multiple ways. By raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses. While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the U.S. Compared to a future without climate change, climate change is expected to increase ozone pollution over broad areas of the U.S., especially on the highest ozone days and in the largest metropolitan areas with the worst ozone problems, and thereby increase the risk of morbidity and mortality. Climate change is also
Climate change impacts touch nearly every aspect of public welfare. Among the multiple threats caused by human emissions of GHGs, climate changes are expected to place large areas of the country at serious risk of reduced water supplies, increased water pollution, and increased occurrence of extreme events such as floods and droughts. Coastal areas are expected to face a multitude of increased risks, particularly from rising sea level and increases in the severity of storms. These communities face storm and flooding damage to property, or even loss of land due to inundation, erosion, wetland submergence and habitat loss.
Impacts of climate change on public welfare also include threats to social and ecosystem services. Climate change is expected to result in an increase in peak electricity demand. Extreme weather from climate change threatens energy, transportation, and water resource infrastructure. Climate change may also exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous communities, and is very likely to fundamentally rearrange U.S. ecosystems over the 21st century. Though some benefits may balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards increasing risks of net adverse impacts on U.S. food production, agriculture and forest productivity as temperature continues to rise. These impacts are global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S.
Since the administrative record concerning the Endangerment Finding closed following the EPA's 2010 Reconsideration Denial, the climate has continued to change, with new records being set for a number of climate indicators such as global average surface temperatures, Arctic sea ice retreat, CO
The EPA has carefully reviewed these recent assessments in keeping with the same approach outlined in Section VIII.A of the 2009 Endangerment Finding, which was to rely primarily upon the major assessments by the USGCRP, the IPCC, and the NRC of the National Academies to provide the technical and scientific information to inform the Administrator's judgment regarding the question of whether GHGs endanger public health and welfare. These assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change issues, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review.
The findings of the recent scientific assessments confirm and strengthen the conclusion that GHGs endanger public health, now and in the future. The NCA3 indicates that human health in the U.S. will be impacted by “increased extreme weather events, wildfire, decreased air quality, threats to mental health, and illnesses transmitted by food, water, and disease-carriers such as mosquitoes and ticks.” The most recent assessments now have greater confidence that climate change will influence production of pollen that exacerbates asthma and other allergic respiratory diseases such as allergic rhinitis, as well as effects on conjunctivitis and dermatitis. Both the NCA3 and the IPCC AR5 found that increasing temperature has lengthened the allergenic pollen season for ragweed, and that increased CO
The NCA3 also finds that climate change, in addition to chronic stresses such as extreme poverty, is negatively affecting indigenous peoples' health in the U.S. through impacts such as reduced access to traditional foods, decreased water quality, and increasing exposure to health and safety hazards. The IPCC AR5 finds that climate change-induced warming in the Arctic and resultant changes in environment (
The NCA3 concludes that children's unique physiology and developing bodies contribute to making them particularly vulnerable to climate change. Impacts on children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. The IPCC AR5 indicates that children are among those especially susceptible to most allergic diseases, as well as health effects
Both the NCA3 and IPCC AR5 conclude that climate change will increase health risks facing the elderly. Older people are at much higher risk of mortality during extreme heat events. Pre-existing health conditions also make older adults susceptible to cardiac and respiratory impacts of air pollution and to more severe consequences from infectious and waterborne diseases. Limited mobility among older adults can also increase health risks associated with extreme weather and floods.
The new assessments also confirm and strengthen the conclusion that GHGs endanger public welfare, and emphasize the urgency of reducing GHG emissions due to their projections that show GHG concentrations climbing to ever-increasing levels in the absence of mitigation. The NRC assessment Understanding Earth's Deep Past projected that, without a reduction in emissions, CO
Future temperature changes will depend on what emission path the world follows. In its high emission scenario, the IPCC AR5 projects that global temperatures by the end of the century will likely be 2.6 °C to 4.8 °C (4.7 to 8.6 °F) warmer than today. Temperatures on land and in northern latitudes will likely warm even faster than the global average. However, according to the NCA3, significant reductions in emissions would lead to noticeably less future warming beyond mid-century, and therefore less impact to public health and welfare.
While rainfall may only see small globally and annually averaged changes, there are expected to be substantial shifts in where and when that precipitation falls. According to the NCA3, regions closer to the poles will see more precipitation, while the dry subtropics are expected to expand (colloquially, this has been summarized as wet areas getting wetter and dry regions getting drier). In particular, the NCA3 notes that the western U.S., and especially the Southwest, is expected to become drier. This projection is consistent with the recent observed drought trend in the West. At the time of publication of the NCA, even before the last 2 years of extreme drought in California, tree ring data was already indicating that the region might be experiencing its driest period in 800 years. Similarly, the NCA3 projects that heavy downpours are expected to increase in many regions, with precipitation events in general becoming less frequent but more intense. This trend has already been observed in regions such as the Midwest, Northeast, and upper Great Plains. Meanwhile, the NRC Climate Stabilization Targets assessment found that the area burned by wildfire is expected to grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of warming, the assessment found that 9 out of 10 summers would be warmer than all but the 5 percent of warmest summers today, leading to increased frequency, duration, and intensity of heat waves. Extrapolations by the NCA also indicate that Arctic sea ice in summer may essentially disappear by mid-century. Retreating snow and ice, and emissions of carbon dioxide and methane released from thawing permafrost, will also amplify future warming.
Since the 2009 Endangerment Finding, the USGCRP NCA3, and multiple NRC assessments have projected future rates of sea level rise that are 40 percent larger to more than twice as large as the previous estimates from the 2007 IPCC 4th Assessment Report due in part to improved understanding of the future rate of melt of the Antarctic and Greenland Ice sheets. The NRC Sea Level Rise assessment projects a global sea level rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) by 2100, the NRC National Security Implications assessment suggests that “the Department of the Navy should expect roughly 0.4 to 2 meters [1.3 to 6.6 feet] global average sea-level rise by 2100,”
In general, climate change impacts are expected to be unevenly distributed across different regions of the U.S. and have a greater impact on certain populations, such as indigenous peoples and the poor. The NCA3 finds climate change impacts such as the rapid pace of temperature rise, coastal erosion and inundation related to sea level rise and storms, ice and snow melt, and permafrost thaw are affecting indigenous people in the U.S. Particularly in Alaska, critical infrastructure and traditional livelihoods are threatened by climate change and, “[i]n parts of Alaska, Louisiana, the Pacific Islands, and other coastal locations, climate change impacts (through erosion and inundation) are so severe that some communities are already relocating from historical homelands to which their traditions and cultural identities are tied.”
Carbon dioxide in particular has unique impacts on ocean ecosystems. The NRC Climate Stabilization Targets assessment found that coral bleaching will increase due both to warming and ocean acidification. Ocean surface waters have already become 30 percent more acidic over the past 250 years due to absorption of CO
Events outside the U.S., as also pointed out in the 2009 Endangerment Finding, will also have relevant consequences. The NRC Climate and Social Stress assessment concluded that it is prudent to expect that some climate events “will produce consequences that exceed the capacity of the affected societies or global systems to manage and that have global security implications serious enough to compel international response.” The NRC National Security Implications assessment recommends preparing for increased needs for humanitarian aid; responding to the effects of climate change in geopolitical hotspots, including possible mass migrations; and addressing changing security needs in the Arctic as sea ice retreats.
In addition to future impacts, the NCA3 emphasizes that climate change driven by human emissions of GHGs is already happening now and it is happening in the U.S. According to the IPCC AR5 and the NCA3, there are a number of climate-related changes that have been observed recently, and these changes are projected to accelerate in the future. The planet warmed about 0.85 °C (1.5 °F) from 1880 to 2012. It is extremely likely (>95 percent probability) that human influence was the dominant cause of the observed warming since the mid-20th century, and likely (>66 percent probability) that human influence has more than doubled the probability of occurrence of heat waves in some locations. In the Northern Hemisphere, the last 30 years were likely the warmest 30 year period of the last 1400 years. U.S. average temperatures have similarly increased by 1.3 to 1.9 degrees F since 1895, with most of that increase occurring since 1970. Global sea levels rose 0.19 m (7.5 inches) from 1901 to 2010. Contributing to this rise was the warming of the oceans and melting of land ice. It is likely that 275 gigatons per year of ice melted from land glaciers (not including ice sheets) since 1993, and that the rate of loss of ice from the Greenland and Antarctic ice sheets increased substantially in recent years, to 215 gigatons per year and 147 gigatons per year respectively since 2002. For context, 360 gigatons of ice melt is sufficient to cause global sea levels to rise 1 mm. Annual mean Arctic sea ice has been declining at 3.5 to 4.1 percent per decade, and Northern Hemisphere snow cover extent has decreased at about 1.6 percent per decade for March and 11.7 percent per decade for June. Permafrost temperatures have increased in most regions since the 1980s, by up to 3 °C (5.4 °F) in parts of Northern Alaska. Winter storm frequency and intensity have both increased in the Northern Hemisphere. The NCA3 states that the increases in the severity or frequency of some types of extreme weather and climate events in recent decades can affect energy production
In addition to the changes documented in the assessment literature, there have been other climate milestones of note. In 2009, the year of the Endangerment Finding, the average concentration of CO
These assessments and observed changes make it clear that reducing emissions of GHGs across the globe is necessary in order to avoid the worst impacts of climate change, and underscore the urgency of reducing emissions now. The NRC Committee on America's Climate Choices listed a number of reasons “why it is imprudent to delay actions that at least begin the process of substantially reducing emissions.”
• The faster emissions are reduced, the lower the risks posed by climate change. Delays in reducing emissions could commit the planet to a wide range of adverse impacts, especially if the sensitivity of the climate to GHGs is on the higher end of the estimated range.
• Waiting for unacceptable impacts to occur before taking action is imprudent because the effects of GHG emissions do not fully manifest themselves for decades and, once manifest, many of these changes will persist for hundreds or even thousands of years.
• In the committee's judgment, the risks associated with doing business as usual are a much greater concern than the risks associated with engaging in strong response efforts.
The NCA3 assessed the climate impacts in 8 regions of the U.S., noting that changes in physical climate parameters such as temperatures, precipitation, and sea ice retreat were already having impacts on forests, water supplies, ecosystems, flooding, heat waves, and air quality. Moreover, the NCA3 found that future warming is projected to be much larger than recent observed variations in temperature, with precipitation likely to increase in the northern states, decrease in the southern states, and with the heaviest precipitation events projected to increase everywhere.
In the Northeast, temperatures increased almost 2 °F from 1895 to 2011, precipitation increased by about 5 inches (10 percent), and sea level rise of about a foot has led to an increase in coastal flooding. The 70 percent increase in the amount of rainfall falling in the 1 percent of the most intense events is a larger increase in extreme precipitation than experienced in any other U.S. region.
In the future, if emissions continue increasing, the Northeast is expected to experience 4.5 to 10 °F of warming by the 2080s. This will lead to more heat waves, coastal and river flooding, and intense precipitation events. The southern portion of the region is projected to see 60 additional days per year above 90 °F by mid-century. Sea levels in the Northeast are expected to increase faster than the global average because of subsidence, and changing ocean currents may further increase the rate of sea level rise. Specific vulnerabilities highlighted by the NCA include large urban populations particularly vulnerable to climate-related heat waves and poor air quality episodes, prevalence of climate sensitive vector-borne diseases like Lyme and West Nile Virus, usage of combined sewer systems that may lead to untreated water being released into local water bodies after climate-related heavy precipitation events, and 1.6 million people living within the 100-year coastal flood zone who are expected to experience more frequent floods due to sea level rise and tropical-storm induced storm-surge. The NCA also highlighted infrastructure vulnerable to inundation in coastal metropolitan areas, potential agricultural impacts from increased rain in the spring delaying planting or damaging crops or increased heat in the summer leading to decreased yields and increased water demand, and shifts in ecosystems leading to declines in iconic species in some regions, such as cod and lobster south of Cape Cod.
In the Southeast, average annual temperature during the last century cycled between warm and cool periods. A warm peak occurred during the 1930s and 1940s followed by a cool period and temperatures then increased again from 1970 to the present by an average of 2 °F. There have been increasing numbers of days above 95 °F and nights above 75 °F, and decreasing numbers of extremely cold days since 1970. Daily and five-day rainfall intensities have also increased, and summers have been either increasingly dry or extremely wet. Louisiana has already lost 1,880 square miles of land in the last 80 years due to sea level rise and other contributing factors.
The Southeast is exceptionally vulnerable to sea level rise, extreme heat events, hurricanes, and decreased water availability. Major consequences of further warming include significant increases in the number of hot days (95 °F or above) and decreases in freezing events, as well as exacerbated ground-level ozone in urban areas. Although projected warming for some parts of the region by the year 2100 are generally smaller than for other regions of the U.S., projected warming for interior states of the region are larger than coastal regions by 1 °F to 2 °F. Projections further suggest that globally there will be fewer tropical storms, but that they will be more intense, with more Category 4 and 5 storms. The NCA identified New Orleans, Miami, Tampa, Charleston, and Virginia Beach as being specific cities that are at risk due to sea level rise, with homes and infrastructure increasingly prone to flooding. Additional impacts of sea level rise are expected for coastal highways, wetlands, fresh water supplies, and energy infrastructure.
In the Northwest, temperatures increased by about 1.3 °F between 1895 and 2011. A small average increase in precipitation was observed over this time period. However, warming temperatures have caused increased rainfall relative to snowfall, which has
Average annual temperatures are projected to increase by 3.3 °F to 9.7 °F by the end of the century (depending on future global GHG emissions), with the greatest warming expected during the summer. Continued increases in global GHG emissions are projected to result in up to a 30 percent decrease in summer precipitation. Earlier snowpack melt and lower summer stream flows are expected by the end of the century and will affect drinking water supplies, agriculture, ecosystems, and hydropower production. Warmer waters are expected to increase disease and mortality in important fish species, including Chinook and sockeye salmon. Ocean acidification also threatens species such as oysters, with the Northwest coastal waters already being some of the most acidified worldwide due to coastal upwelling and other local factors. Forest pests are expected to spread and wildfires burn larger areas. Other high-elevation ecosystems are projected to be lost because they can no longer survive the climatic conditions. Low lying coastal areas, including the cities of Seattle and Olympia, will experience heightened risks of sea level rise, erosion, seawater inundation and damage to infrastructure and coastal ecosystems.
In Alaska, temperatures have changed faster than anywhere else in the U.S. Annual temperatures increased by about 3 °F in the past 60 years. Warming in the winter has been even greater, rising by an average of 6 °F. Arctic sea ice is thinning and shrinking in area, with the summer minimum ice extent now covering only half the area it did when satellite records began in 1979. Glaciers in Alaska are melting at some of the fastest rates on Earth. Permafrost soils are also warming and beginning to thaw. Drier conditions have contributed to more large wildfires in the last 10 years than in any previous decade since the 1940s, when recordkeeping began. Climate change impacts are harming the health, safety and livelihoods of Native Alaskan communities.
By the end of this century, continued increases in GHG emissions are expected to increase temperatures by 10 to 12 °F in the northernmost parts of Alaska, by 8 to 10 °F in the interior, and by 6 to 8 °F across the rest of the state. These increases will exacerbate ongoing arctic sea ice loss, glacial melt, permafrost thaw and increased wildfire, and threaten humans, ecosystems, and infrastructure. Precipitation is expected to increase to varying degrees across the state, however warmer air temperatures and a longer growing season are expected to result in drier conditions. Native Alaskans are expected to experience declines in economically, nutritionally, and culturally important wildlife and plant species. Health threats will also increase, including loss of clean water, saltwater intrusion, sewage contamination from thawing permafrost, and northward extension of diseases. Wildfires will increasingly pose threats to human health as a result of smoke and direct contact. Areas underlain by ice-rich permafrost across the state are likely to experience ground subsidence and extensive damage to infrastructure as the permafrost thaws. Important ecosystems will continue to be affected. Surface waters and wetlands that are drying provide breeding habitat for millions of waterfowl and shorebirds that winter in the lower 48 states. Warmer ocean temperatures, acidification, and declining sea ice will contribute to changes in the location and availability of commercially and culturally important marine fish.
In the Southwest, temperatures are now about 2 °F higher than the past century, and are already the warmest that region has experienced in at least 600 years. The NCA notes that there is evidence that climate-change induced warming on top of recent drought has influenced tree mortality, wildfire frequency and area, and forest insect outbreaks. Sea levels have risen about 7 or 8 inches in this region, contributing to inundation of Highway 101 and backup of seawater into sewage systems in the San Francisco area.
Projections indicate that the Southwest will warm an additional 5.5 to 9.5 °F over the next century if emissions continue to increase. Winter snowpack in the Southwest is projected to decline (consistent with the record lows from this past winter), reducing the reliability of surface water supplies for cities, agriculture, cooling for power plants, and ecosystems. Sea level rise along the California coast will worsen coastal erosion, increase flooding risk for coastal highways, bridges, and low-lying airports, pose a threat to groundwater supplies in coastal cities such as Los Angeles, and increase vulnerability to floods for hundreds of thousands of residents in coastal areas. Climate change will also have impacts on the high-value specialty crops grown in the region as a drier climate will increase demands for irrigation, more frequent heat waves will reduce yields, and decreased winter chills may impair fruit and nut production for trees in California. Increased drought, higher temperatures, and bark beetle outbreaks are likely to contribute to continued increases in wildfires. The highly urbanized population of the Southwest is vulnerable to heat waves and water supply disruptions, which can be exacerbated in cases where high use of air conditioning triggers energy system failures.
The rate of warming in the Midwest has markedly accelerated over the past few decades. Temperatures rose by more than 1.5 °F from 1900 to 2010, but between 1980 and 2010 the rate of warming was three times faster than from 1900 through 2010.
Precipitation generally increased over the last century, with much of the increase driven by intensification of the heaviest rainfalls. Several types of extreme weather events in the Midwest (
In the future, if emissions continue increasing, the Midwest is expected to experience 5.6 to 8.5 °F of warming by the 2080s, leading to more heat waves. Though projections of changes in total precipitation vary across the regions, more precipitation is expected to fall in the form of heavy downpours across the entire region, leading to an increase in flooding. Specific vulnerabilities highlighted by the NCA include long-term decreases in agricultural productivity, changes in the composition of the region's forests, increased public health threats from heat waves and degraded air and water quality, negative impacts on transportation and other infrastructure associated with extreme rainfall events and flooding, and risks to the Great Lakes including shifts in invasive species, increases in harmful algal blooms, and declining beach health.
High temperatures (more than 100 °F in the Southern Plains and more than 95 °F in the Northern Plains) are projected to occur much more frequently by mid-century. Increases in extreme heat will increase heat stress for residents, energy demand for air conditioning, and water losses. North Dakota's increase in annual temperatures over the past 130 years is the fastest in the contiguous U.S., mainly driven by warming winters. Specific vulnerabilities highlighted by the NCA include increased demand for water and energy, changes to crop growth cycles and
In Hawaii, other Pacific islands, and the Caribbean, rising air and ocean temperatures, shifting rainfall patterns, changing frequencies and intensities of storms and drought, decreasing baseflow in streams, rising sea levels, and changing ocean chemistry will affect ecosystems on land and in the oceans, as well as local communities, livelihoods, and cultures. Low islands are particularly at risk.
Rising sea levels, coupled with high water levels caused by tropical and extra-tropical storms, will incrementally increase coastal flooding and erosion, damaging coastal ecosystems, infrastructure, and agriculture, and negatively affecting tourism. Ocean temperatures in the Pacific region exhibit strong year-to-year and decadal fluctuations, but since the 1950s, they have exhibited a warming trend, with temperatures from the surface to a depth of 660 feet rising by as much as 3.6 °F. As a result of current sea level rise, the coastline of Puerto Rico around Rincón is being eroded at a rate of 3.3 feet per year. Freshwater supplies are already constrained and will become more limited on many islands. Saltwater intrusion associated with sea level rise will reduce the quantity and quality of freshwater in coastal aquifers, especially on low islands. In areas where precipitation does not increase, freshwater supplies will be adversely affected as air temperature rises.
Warmer oceans are leading to increased coral bleaching events and disease outbreaks in coral reefs, as well as changed distribution patterns of tuna fisheries. Ocean acidification will reduce coral growth and health. Warming and acidification, combined with existing stresses, will strongly affect coral reef fish communities. For Hawaii and the Pacific islands, future sea surface temperatures are projected to increase 2.3 °F by 2055 and 4.7 °F by 2090 under a scenario that assumes continued increases in emissions. Ocean acidification is also taking place in the region, which adds to ecosystem stress from increasing temperatures. Ocean acidity has increased by about 30 percent since the pre-industrial era and is projected to further increase by 37 percent to 50 percent from present levels by 2100.
The NCA also discussed impacts that occur along the coasts and in the oceans adjacent to many regions, and noted that other impacts occur across regions and landscapes in ways that do not follow political boundaries.
Fossil fuel-fired electric utility generating units (EGUs) are by far the largest emitters of GHGs among stationary sources in the U.S., primarily in the form of CO
The EPA implements a separate program under 40 CFR part 98 called the Greenhouse Gas Reporting Program
The EPA prepares the official U.S. GHG Inventory to comply with commitments under the United Nations Framework Convention on Climate Change (UNFCCC). This inventory, which includes recent trends, is organized by industrial sectors. It provides the information in Table 3 below, which presents total U.S. anthropogenic
Total fossil energy-related CO
In
Carbon
Unlike other air pollutants which are results of trace impurities in the fuel, products of incomplete or inefficient combustion, or combustion byproducts, CO
It should be noted that PM
CO
The properties of CO
The modern American electricity system is one of the greatest engineering achievements of the past 100 years. Since the invention of the incandescent light bulb in the 1870s,
Initially, states had broad authority to regulate public utilities, but gradually federal regulation increased. In 1920, Congress passed the Federal Water Power Act, creating the Federal Power Commission (FPC) and providing for the licensing of hydroelectric facilities on U.S. government lands and navigable waters of the U.S.
By the 1930s, regulated electric utilities that provided the major components of the electrical system—generation, transmission, and distribution—were common.
As utilities built larger and larger electric generation plants, the cost per unit to generate electricity decreased.
In the past, electric utilities generally operated as state regulated monopolies, supplying end-use customers with generation, distribution, and transmission service.
On both a federal and state level, competition has entered the electricity sector to varying degrees in the last few decades.
Over time, the grid slowly evolved into a complex, interconnected transmission system that allows electric generators to produce electricity that is then fed onto transmission lines at high voltages.
The North American electric grid has developed into a large, interconnected system.
Today, federal, state, and local entities regulate electricity providers.
System operators typically dispatch the electric system through a process known as Security Constrained Economic Dispatch.
The decision to dispatch any particular electric generator depends upon the relative operating cost, or marginal cost, of generating electricity to meet the last increment of electric demand. Fuel is one common variable cost—especially for fossil-fueled generators. Coal plants will often have considerable variable costs associated with running pollution controls.
In states with cost-of-service regulation of vertically-integrated utilities, the utilities themselves form the balancing authorities who determine dispatch based upon the lowest marginal cost. These utilities sometimes arrange to buy and sell electricity with other balancing authorities. RTOs and ISOs coordinate, control, and monitor electricity transmission systems to ensure cost-effective and reliable delivery of power, and they are independent from market participants.
The reliability of the electric system has long been a focus of the electric industry and regulators. Industry developed a voluntary organization in the early 1960s that assisted with bulk power system coordination in the U.S. and Canada.
In August 2003, North America experienced its worst blackout to date creating an outage in the Midwest, Northeast, and Ontario, Canada.
Congress responded to this recommendation in EPAct 2005, adding a new section 215 to the Federal Power Act making reliability standards mandatory and enforceable and authorizing the creation of a new Electric Reliability Organization (ERO). Under this new system, FERC certifies an entity as the ERO. The ERO develops reliability standards, which are subject to FERC review and approval. Once FERC approves reliability standards the ERO may enforce those standards or FERC can do so independently.
The U.S., Canada, and part of Mexico are divided up into eight reliability
Today, the electricity sector is undergoing a period of intense change. Fossil fuels—such as coal, natural gas, and oil—have historically provided a large percentage of electricity in the U.S., along with nuclear power, with smaller amounts provided by other types of generation, including renewables such as wind, solar, and hydroelectric power. Coal provided the largest percentage of the fossil fuel generation.
While the change in the resource mix has accelerated in recent years, wind, solar, other renewables, and EEresources have been reliably participating in the electric sector for a number of years. This rapid development of non-fossil fuel resources is occurring as much of the existing power generation fleet in the U.S. is aging and in need of modernization and replacement. In 2025, the average age of the coal-fired generating fleet is projected to be 49 years old, and 20 percent of those units would be more than 60 years old if they remain in operation at that time. In its
Natural gas has a long history of meeting electricity demand in the U.S., with a rapidly growing role as domestic supplies of natural gas have dramatically increased. Natural gas net generation increased by approximately 32 percent between 2005 and 2014.
Renewable sources of electric generation also have a history of meeting electricity demand in the U.S. and are expected to have an increasing role going forward. A series of energy crises provided the impetus for RE development in the early 1970s. The OPEC oil embargo in 1973 and oil crisis of 1979 caused oil price spikes, more frequent energy shortages, and significantly affected the national and global economy. In 1978, partly in response to fuel security concerns, Congress passed the Public Utilities Regulatory Policies Act (PURPA) which required local electric utilities to buy power from qualifying facilities (QFs).
Use of RE continues to grow rapidly in the U.S. In 2013, electricity generated from renewable technologies, including conventional hydropower, represented 13 percent of total U.S. electricity, up from 9 percent in 2005.
The global market for RE is projected to grow to $460 billion per year by 2030.
Price pressures caused by oil embargoes in the 1970s also brought the issues of conservation and EE to the forefront of U.S. energy policy.
Advancements and innovation in power sector technologies provide the opportunity to address CO
In this section, we provide a general description of major CAA regulations for power plants. We refer to these in later sections of this preamble.
The EPA's Acid Rain Program, established in 1990 under Title IV of the CAA, addresses the presence of acidic compounds and their precursors (
The SO
The second phase, beginning in 2000, expanded coverage to more than 2,000 generating units and set a national cap at 8.90 million tons.
Title IV also required the EPA to hold or sponsor annual auctions and sales of allowances for a small portion of the total allowances allocated each year. This ensured that some allowances would be directly available for new sources, including independent power production facilities.
The provisions of the EPA's Acid Rain Program are implemented through permits issued under the EPA's Title V Operating Permit Program.
CAA section 110(a)(2)(D)(i)(I), the “Good Neighbor Provision,” requires SIPs to prohibit emissions that “contribute significantly to nonattainment . . . or interfere with maintenance” of the NAAQS in any other state.
In three major rulemakings—the NO
a.
b.
c.
On March 15, 2005, the EPA issued a rule to control mercury (Hg) emissions from new and existing fossil fuel-fired power plants under CAA section 111(b) and (d). The rule, known as the Clean Air Mercury Rule (CAMR), established, in relevant part, a nationwide cap-and-trade program under CAA section 111(d), which was designed to complement the cap-and-trade program for SO
The cap-and-trade program in CAMR was designed to take effect in two phases: in 2010, the cap was set at 38 tons of mercury per year, and in 2018, the cap would be lowered to 15 tons per year. The Phase I cap was set at a level reflecting the co-benefits of CAIR as determined through economic and environmental modeling.
To accompany the nationwide emissions cap, the EPA also assigned a statewide emissions budget for mercury. Pursuant to CAA section 111(d), states would be required to submit plans to the EPA “detailing the controls that will be implemented to meet its specified budget for reductions from coal-fired Utility Units.”
On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to reduce emissions of toxic air pollutants from new and existing coal- and oil-fired EGUs. The MATS rule will reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel; and acid gases, including hydrochloric acid and hydrofluoric acid. These toxic air pollutants, also known as hazardous air pollutants or air toxics, are known to cause, or suspected of causing, nervous system damage, cancer, and other serious health effects. The MATS rule will also reduce SO
New or reconstructed EGUs (
Existing sources subject to the MATS rule were required to begin meeting the rule's requirements on April 16, 2015. Controls that will achieve the MATS performance standards are being installed on many units. Certain units, especially those that operate infrequently, may be considered not worth investing in given today's electricity market, and are closing. The final MATS rule provided a foundation on which states and other permitting authorities could rely in granting an additional, fourth year for compliance provided for by the CAA. States report that these fourth year extensions are being granted. In addition, the EPA issued an enforcement policy that provides a clear pathway for reliability-critical units to receive an administrative order that includes a compliance schedule of up to an additional year, if it is needed to ensure electricity reliability.
Following promulgation of the MATS rule, industry, states and environmental organizations challenged many aspects of the EPA's threshold determination that regulation of EGUs is “appropriate and necessary” and the final standards regulating hazardous air pollutants from EGUs. The U.S. Court of Appeals for the D.C. Circuit upheld all aspects of the MATS rule.
Under CAA section 169A, Congress “declare[d] as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility” in national parks and wilderness areas that results from anthropogenic emissions.
In 1999, the EPA promulgated the Regional Haze Rule to satisfy Congress' mandate that EPA promulgate regulations directing states to address visibility impairment.
The Regional Haze Rule set a goal of achieving natural visibility conditions by 2064 and requires states to revise their regional haze SIPs every ten years.
During its deliberations on the 1970 Clean Air Act Amendments, Congress learned that ongoing pollution, including from manmade carbon dioxide, could “threaten irreversible atmospheric and climatic changes.”
Scientific reports on climatic change continued to gain traction in Congress through the mid-1970s, including while Congress was considering the 1977 CAA Amendments. However, uncertainty continued as to whether the increased warming brought about by carbon dioxide emissions would be offset by cooling brought about by particulate emissions.
Between the 1977 and 1990 Clean Air Act Amendments, scientific uncertainty yielded to the predominant view that global warming “was likely to dominate on time scales that would be significant to human societies.”
Energy efficiency is a crucial tool for controlling the emissions of carbon dioxide, the gas chiefly responsible for the intensification of the atmospheric `greenhouse effect.' In the last several years, the Committee has received extensive scientific testimony that increases in the human-caused emissions of carbon dioxide and other greenhouse gases will lead to catastrophic shocks in the global climate system. Accordingly, new title IV shapes an acid rain reduction policy that encourages energy efficiency and other policies aimed at controlling greenhouse gases.
In this final rule, the U.S. is taking action to limit GHGs from one of its largest emission sources. Climate change is a global problem, and the U.S. is not alone in taking action to address it. The UNFCCC
Many countries have announced their intended post-2020 commitments already, and other countries are expected to do so before December. In April 2015, the U.S. announced its commitment to reduce GHG emissions 26-28 percent below 2005 levels by 2025.
As Parties to both the UNFCCC and the Kyoto Protocol,
Recently, China has also agreed to take action to address climate change. In November 2014, in a joint announcement by President Obama and China's President Xi, China pledged to curtail GHG emissions, with emissions peaking in 2030 and then declining thereafter, and to increase the share of energy from non-carbon sources (solar, wind, hydropower, nuclear) to 20 percent by 2030.
Mexico is committed to reduce unconditionally 25 percent of its emissions of GHGs and short-lived climate pollutants (below business as usual) for the year 2030. This commitment implies a 22 percent reduction of GHG emissions and a 51 percent reduction of black carbon emissions.
Brazil has reduced its net CO
Together, countries that have already announced their intended post-2020 commitments, including the U.S., China, European Union, Mexico, Russian Federation and Brazil, make up a large majority of global emissions.
President Obama's Climate Action Plan contains a number of policies and programs that are intended to cut carbon pollution that causes climate change and affects public health. The Clean Power Plan is a key component of the plan, addressing the nation's largest source of emissions in a comprehensive manner. Collectively, these policies will help spark business innovation, result in cleaner forms of energy, create jobs, and cut dependence on foreign oil. They also demonstrate to the rest of the world that the U.S. is contributing its share of the global effort that is needed to address climate change.
“The actions I've announced today should send a strong signal to the world that America intends to take bold action to reduce carbon pollution. We will continue to lead by the power of our example, because that's what the United States of America has always done.” President Obama, Climate Action Plan speech, Georgetown University, 2013. Available at
This mobilization of American effort matters. Enormously. It matters because the United States is the biggest economy and largest historic emitter of greenhouse gases. Because, here, as in so many areas, we feel a responsibility to lead. And because here, as in so many areas, we find that American commitment is indispensable to effective international action.
And make no mistake—other countries see what we are doing and are taking note. As I travel the world and meet with my
This final rule demonstrates to other countries that the U.S. is taking action to limit GHG emissions from its largest emission sources, in line with our international commitments. The impact of GHGs is global, and U.S. action to reduce GHG emissions complements and encourages ongoing programs and efforts in other countries.
In the final days of December 1970, Congress enacted sweeping changes to the Air Quality Act of 1967 to confront an “environmental crisis.”
For the most part, Congress gave EPA and the states flexible tools to implement the CAA. This is best exhibited by the newly enacted programs regulating stationary sources. For these sources, Congress crafted a three-legged regime upon which the regulation of stationary sources was intended to sit.
The first prong—CAA sections 107-110—addressed what are commonly referred to as criteria pollutants, “the presence of which in the ambient air results from numerous or diverse mobile or stationary sources” and are determined to have “an adverse effect on public health or welfare”.
The second prong—CAA section 111—addressed pollutants on a source category-wide basis. Under CAA section 111(b), the EPA lists source categories which “contribute significantly to air pollution which causes or contributes to the endangerment of public health or welfare,” And then establishes “standards of performance” for the new sources in the listed category.
Lastly, the third prong—CAA section 112—addressed hazardous air pollutants through the establishment of national “emission standards” at a level which “provides an ample margin of safety to protect the public health”.
At its inception, CAA section 111 was intended to bear a significant weight under this three-legged regime. Indeed, by 1977, the EPA had promulgated six times as many performance standards under CAA section 111 than emission standards under CAA section 112.
At bottom, CAA section 111 rests on the definition of a standard of performance under CAA section 111(a)(1), which reads nearly the same now as it did when it was first adopted in the 1970 CAA Amendments. In 1970, Congress defined standard of performance—a term which had not previously appeared in the CAA—as
Despite significant changes to this definition in 1977, Congress reversed course in 1990 and largely reinstated the original definition.
The level of control reflected in the definition is generally referred to as the “best system of emission reduction,” or the BSER. The BSER, however, is not further defined, and only appeared after conference between the House and Senate in late 1970, and was neither discussed in the conference report nor openly debated in either chamber. Nevertheless, the originating bills from both houses shed light on its construction.
The BSER grew out of proposed language in two bills, which, for the first time, targeted air pollution from stationary sources. The House bill sought to establish national emission standards to “prevent and control . . . emissions [of non-hazardous pollutants] to the fullest extent compatible with the available technology and economic feasibility.”
After conference, CAA section 111 emerged as one of the CAA's three programs for regulating stationary sources. In defining the newly formed “standards of performance,” Congress appeared to merge the various “means of preventing and controlling air pollution” under the Senate bill with the consideration of costs that was central to the House bill into the BSER. At the time, however, this definition only applied to new sources under CAA section 111(b).
To regulate existing sources, Congress collapsed section 114 of the Senate bill into CAA section 111(d).
As adopted, CAA section 111(d) requires states to submit plans to the Administrator establishing “emission standards” for certain existing sources of air pollutants that were not otherwise regulated as criteria pollutants or hazardous air pollutants. This ensured that there would be “no gaps in control activities pertaining to stationary source emissions that pose any significant danger to public health or welfare.”
The term “emission standards,” however, was not expressly defined in the 1970 CAA Amendments (save for purposes of citizen suit enforcement) even though the term was also used under the CAA's SIP provisions and CAA section 112.
After the enactment of the 1970 CAA Amendments, the EPA proposed standards of performance for an “initial list of five stationary source categories which contribute significantly to air pollution” in August 1971.
Several years later, the EPA proposed its implementing regulations for CAA section 111(d).
Despite these first steps taken under CAA sections 111(b) and (d), Congress revisited the CAA in 1977 to address growing concerns with the nation's response to the 1973 oil embargo (noted above), to respond to new environmental problems such as stratospheric ozone depletion, and to resolve other issues associated with implementing the 1970 CAA Amendments.
Congress also made significant changes to CAA section 111. For example, Congress amended the definition of a standard of performance (including by requiring the consideration of “nonair quality health and environmental impact and energy requirements”), authorized alternative (
The 1977 definition for a standard of performance required “all new sources to meet emission standards based on the reductions achievable through the use of the ‘best technological system of continuous emission reduction.’ ”
Congress also clarified that with respect to CAA section 111(d), standards of performance (now applicable in lieu of emission standards) “would be based on the best available means (not necessarily technological)”.
In the twenty years since the 1970 CAA Amendments and in spite of the refinements of the 1977 CAA Amendments, “many of the Nation's most important air pollution problems [had] failed to improve or [had] grown more serious.”
All told, however, there was minimal debate on changes to CAA section 111. In fact, the only discussion centered on the repeal of the percentage reduction requirement, which became seen as unduly restrictive. Accordingly, Congress reverted the definition of “standard of performance” to the definition agreed to in the 1970 CAA Amendments, but retained the requirement to consider nonair quality environmental impacts and energy requirements added in 1977.
Clean Air Act section 111, which Congress enacted as part of the 1970 Clean Air Act Amendments, establishes mechanisms for controlling emissions of air pollutants from stationary sources. This provision requires the EPA to promulgate a list of categories of stationary sources that the Administrator, in his or her judgment, finds “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.”
When the EPA establishes NSPS for new sources in a particular source category, the EPA is also required, under CAA section 111(d)(1), to prescribe regulations for states to submit plans regulating existing sources in that source category for any air pollutant that, in general, is not regulated under the CAA section 109 requirements for the NAAQS or regulated under the CAA section 112 requirements for HAP. CAA section 111(d)'s mechanism for regulating existing sources differs from the one that CAA section 111(b) provides for new sources because CAA section 111(d) contemplates states submitting plans that establish “standards of performance” for the affected sources and that contain other measures to implement and enforce those standards.
“Standards of performance” are defined under CAA section 111(a)(1) as standards for emissions that reflect the emission limitation achievable from the “best system of emission reduction,” considering costs and other factors, that “the Administrator determines has been adequately demonstrated.” CAA section 111(d)(1) grants states the authority, in applying a standard of performance to a particular source, to take into account the source's remaining useful life or other factors.
Under CAA section 111(d), a state must submit its plan to the EPA for approval, and the EPA must approve the state plan if it is “satisfactory.”
Section 302(d) of the CAA defines the term “state” to include the Commonwealth of Puerto Rico, the Virgin Islands, Guam, American Samoa and the Commonwealth of the Northern Mariana Islands. While 40 CFR part 60 contains a separate definition of “state” at section 60.2, this definition expands on, rather than narrows, the definition in section 302(d) of the CAA. The introductory language to 40 CFR 60.2 provides: “The terms in this part are defined in the Act or in this section as follows.” Section 60.2 defines “State” as
Section 301(d)(A) of the CAA recognizes that the American Indian tribes are sovereign Nations and authorizes the EPA to “treat tribes as States under this Act”. The Tribal Authority Rule (63 FR 7254, February 12, 1998) identifies that EPA will treat tribes in a manner similar to states for all of the CAA provisions with the exception of, among other things, specific plan submittal and implementation deadlines under the CAA. As a result, though they operate as part of the interconnected system of electricity production and distribution, affected EGUs located in Indian country would not be encompassed within a state's CAA section 111(d) plan. Instead, an Indian tribe with one or more affected EGUs located in its area of Indian country
In these final emission guidelines, the term “state” encompasses the 50 states and the District of Columbia, U.S. territories, and any Indian tribe that has been approved by the EPA pursuant to 40 CFR 49.9 as to develop and implement a CAA section 111(d) plan.
The EPA issued regulations implementing CAA section 111(d) in 1975,
Over the last forty years, under CAA section 111(d), the agency has regulated four pollutants from five source categories (
The EPA's previous CAA section 111(d) actions were necessarily geared toward the pollutants and industries regulated. Similarly, in this rulemaking, in defining CAA section 111(d) emission guidelines for the states and determining the BSER, the EPA believes that taking into account the particular characteristics of carbon pollution, the interconnected nature of the power sector and the manner in which EGUs are currently operated is warranted. Specifically, the operators themselves treat increments of generation as interchangeable between and among sources in a way that creates options for relying on varying utilization levels, lowering carbon generation, and reducing demand as components of the overall method for reducing CO
In this action, the EPA is promulgating emission guidelines for states to follow in developing their CAA section 111(d) plans to reduce emissions of CO
On June 18, 2014, the EPA proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing fossil fuel-fired electric generating units (EGUs). Specifically, the EPA proposed rate-based goals for CO
The EPA also issued two documents after the June 18, 2014 proposal. On October 30, 2014, the EPA published a NODA in which the agency provided additional information on several topics raised by stakeholders and solicited comment on the information presented. This action covered three topic areas: 1) the emission reduction compliance trajectories created by the interim goal for 2020 to 2029, 2) certain aspects of the building block methodology, and 3) the way state-specific CO
In a separate action, the EPA published a document regarding potential methods for determining the mass that is equivalent to an emission rate-based CO
Following the direction in the Presidential Memorandum to the Administrator (June 25, 2013),
Throughout the rulemaking process, the agency has encouraged, organized, and participated in hundreds of meetings about CAA section 111(d) and reducing carbon pollution from existing power plants. The agency's outreach prior to proposal, as well as during the public comment period, was designed to solicit policy ideas,
Our engagement has brought together a variety of states and stakeholders to discuss a wide range of issues related to the utility power sector and the development of emission guidelines under CAA section 111(d). The meetings were attended by the EPA Regional Administrators, other senior managers and staff who have been instrumental in the development of the rule and will play key roles in developing and implementing it.
This outreach process has produced a wealth of information which has informed this rule significantly. The pre-proposal outreach efforts far exceeded what is required of the agency in the normal course of a rulemaking process, and the EPA expects that the dialogue with states and stakeholders will continue after the rule is finalized. The EPA recognizes the importance of working with all stakeholders, and in particular with the states, to ensure a clear and common understanding of the role the states will play in addressing carbon pollution from power plants. We firmly believe that our outreach has resulted in a more workable rule that will achieve the statutory goals and has enhanced the likelihood of timely and successful achievement of the carbon reduction goals, given the critical importance and urgency of the concrete action.
The EPA has given stakeholder comments careful consideration and, as a result, this final rule includes features that are responsive to many stakeholder concerns.
More than 2,700 people attended the public hearings sessions held in Atlanta, Denver, Pittsburgh, and Washington, DC. More than 1,300 people spoke at the public hearings. Additionally, about 100 people attended the public hearing held in Phoenix, Arizona, on the November 4, 2014 supplemental proposal. Speakers at the public hearings included Members of Congress, other public officials, industry representatives, faith-based organizations, unions, environmental groups, community groups, students, public health groups, energy groups, academia and concerned citizens.
Participants shared a range of perspectives. Many were concerned with the impacts of climate change on their health and on future generations, others were worried about the impact of regulations on the economy. Their support for the agency's efforts varied.
Since fall 2013, the agency has provided multiple opportunities for the states to inform this rulemaking. Administrator McCarthy has engaged with governors from states with a variety of interests in the rulemaking. Other senior agency officials have engaged with every branch and major agency of state government—including state legislators, attorneys general, state energy, environment, and utility officials, and governors' staff.
On several occasions, state environmental commissioners met with senior agency officials to provide comments on the Clean Power Plan. The EPA organized, encouraged and attended meetings with states to discuss multi-state planning efforts. States have come together with several collaborative groups to discuss ways to work together to make the Clean Power Plan more affordable. The EPA has participated in and supported the states in these discussions. Because of the interconnectedness of the power sector, and the fact that electricity generated at power plants crosses state lines; states, utilities and ratepayers may benefit from states working together to implement the requirements of this rulemaking. The meetings provided state leaders, including governors, environmental commissioners, energy officers, public utility commissioners, and air directors, opportunities to engage with the EPA officials. In addition, the states
Agency officials listened to ideas, concerns and details from states, including from states with a wide range of experience in reducing carbon pollution from power plants. The EPA reached out to all 50 states to engage with both environmental and energy departments at all levels of government. As an example, a three-part webinar series in June/July 2014 for the states and tribes offered an interactive format for technical staff at the EPA and in the states/tribes to exchange ideas and ask clarifying question. The webinars were then posted online so other stakeholders could view them. A few weeks after the postings, the EPA organized follow-up conference calls with stakeholder groups. Also, the EPA hosted scores of technical meetings between states and the EPA in the weeks and months after the rule was proposed.
Additionally, the EPA organized “hub” calls; these teleconferences brought all of the states in a given EPA region together to discuss technical and interstate aspects of the proposal. These exchanges helped provide the stakeholders with the information they needed to comment on the proposal effectively. The EPA also held a series of webinars with state environmental associations and their members on a series of technical issues.
The agency has collected policy papers and comment letters from states with overarching energy goals and technical details on the states' utility power sector. EPA leadership and staff also participated in webinars and meetings with state and tribal officials hosted by collaborative groups and trade associations. After the comment period closed, and based on our meetings over the last year, as well as written comments on the proposal and NODA, the EPA analyzed information about data errors that needed to be addressed for the final rule. In February and March 2015, we reached out to particular states to clarify ambiguous or unclear information that was submitted to the EPA related to NEEDS and eGRID data. The EPA contacted particular states to clarify the technical comments or concerns to ensure that any changes we make are accurate and appropriate.
To help prepare for implementation of this rule, the agency initiated several outreach activities to assist with state planning efforts. The agency participated in meetings organized by the National Association of State Energy Officials (NASEO), the National Association of Regulatory Utility Commissioners (NARUC), and the National Association of Clean Air Agencies (NACAA) (the “3N” groups). Meeting participants discussed issues related to EE and RE.
To help state officials prepare for the planning process that will take place in the states, the EPA presented a webinar on February 24, 2015. This webinar provided an update on training plans and further connection with states in the implementation process. Forty-nine states, the District of Columbia, and 14 tribes were represented at this webinar. The EPA is developing a state plan electronic collection system to receive, track, and store state submittals of plans and reports. The EPA plans to use an integrated project team to solicit stakeholder input on the system during development. The team membership, including state representatives, will bring together the business and technology skills required to construct a successful product and promote transparency in the EPA's implementation of the rule.
To help identify training needs for the final Clean Power Plan, the agency reached out to a number of state and local organizations such as the Central State Air Resources Agencies and other such regional air agencies. The EPA's outreach on training has included sharing the plans with the states and incorporating changes to the training topics based on the states' needs. The EPA training plan includes a wide variety of topics such as basic training on the electric power sector as well as specific pollution control strategies to reduce carbon emissions from power plants. In particular, the states requested training on how to use programs such as combined heat and power, EE and RE to reduce carbon emissions. The EPA will continue to work with states to tailor training activities to their needs.
The agency has engaged, and will continue to engage with states, territories, Washington, DC, and tribes after the rulemaking process and throughout implementation.
The EPA conducted significant outreach to and consultation with tribes. Tribes are not required to, but may, develop or adopt Clean Air Act programs. The EPA is aware of four facilities with affected EGUs located in Indian country: the South Point Energy Center, in Fort Mojave Indian country, geographically located within Arizona; the Navajo Generating Station, in Navajo Indian country, geographically located within Arizona; the Four Corners Power Plant, in Navajo Indian country, geographically located within New Mexico; and the Bonanza Power Plant, in Ute Indian country, geographically located within Utah. The EPA offered consultation to the leaders of the tribes on whose lands these facilities are located as well as all of the federally recognized tribes to ensure that they had the opportunity to have meaningful and timely input into this rule. Section III (“Stakeholder Outreach and Conclusions”) of the June 18, 2014 proposal documents the EPA's extensive outreach efforts to tribal officials prior to that proposal, including an informational webinar, outreach meeting, teleconferences with tribal officials and the National Tribal Air Association (NTAA), and letters offering consultation. Additional outreach to tribal officials conducted by the EPA prior to the November 4, 2014 supplemental proposal is discussed in Section II.D (“Additional Outreach and Consultation”) of the supplemental proposal. The additional outreach for the supplemental proposal included consultations with all three tribes that have affected EGUs on their lands, as well as several other tribes that requested consultation, and also additional teleconferences with the NTAA.
After issuing the supplemental proposal, the EPA offered an additional consultation to the leaders of all federally recognized tribes. The EPA held an informational meeting open to all tribes and also held consultations with the Navajo Nation, Fort McDowell Yavapai Nation, Fort Mojave Tribe, Ak-Chin Indian Community, and Hope Tribe on November 18, 2014. The EPA held a consultation with the Ute Tribe of the Uintah and Ouray Reservation on December 16, 2014, and a consultation with the Gila River Indian Community on January 15, 2015. The EPA held a public hearing on the supplemental proposal on November 19, 2014, in Phoenix, Arizona. On April 28, 2015, the EPA held an additional consultation with the Navajo Nation.
Tribes were interested in the impact of this rule on other ongoing regulatory actions at the affected EGUs, such as permitting or requirements for the best available retrofit technology (BART). Tribes also noted that it was important to allow RE projects on tribal lands to contribute toward meeting state goals. Some tribes indicated an interest in being involved in the development of implementation plans for areas of Indian country. Additional detail regarding the EPA's outreach to tribes and comments and recommendations from tribes can be found in Section X.F of this preamble.
The EPA has met with individual U.S. territories and affected EGUs in U.S. territories during the rulemaking process. On July 22, 2014, the EPA met with representatives from the Puerto Rico Environmental Quality Board, the Puerto Rico Electric Power Authority, the Governor's Office, and the Office of Energy, Puerto Rico. On September 8, 2014, the EPA held a meeting with representatives from the Guam Environmental Protection Agency (GEPA) and the Guam Power Authority and, on February 18, 2015, the EPA met again with representatives from GEPA.
Agency officials have engaged with industry leaders and representatives from trade associations in many one-on-one and national meetings. Many meetings occurred at the EPA headquarters and in the EPA's Regional Offices and some were sponsored by stakeholder groups. Because the focus of the rule is on the utility power sector, many of the meetings with industry have been with utilities and industry representatives directly related to the utility power sector. The agency has also met with energy industries such as coal and natural gas interests, as well as companies that offer new technology to prevent or reduce carbon pollution, including companies that have expertise in RE and EE. Other meetings have been held with representatives of energy intensive industries, such as the iron and steel and aluminum industries, to help understand the issues related to large industrial users of electricity.
Agency officials participated in many meetings with utilities and their associations to discuss all aspects of the proposed guidelines. We have met with all types of companies that produce electricity, including private utilities or investor owned utilities. Public utilities and cooperative utilities were also part of in-depth conversations about CAA section 111(d) with EPA officials.
The conversations included meetings with the EPA headquarters and regional offices. State officials were included in many of the meetings. Meetings with utility associations and groups of utilities were held with key EPA officials. The meetings covered technical, policy and legal topics of interest and utilities expressed a wide variety of support and concerns about CAA section 111(d).
The EPA had a number of conversations with the ISOs and RTOs to discuss the rule and issues related to grid operations and reliability. EPA staff met with the ISO/RTO Council on several occasions to collect their ideas. The EPA regional offices also met with the ISOs and RTOs in their regions. System operators have offered suggestions in using regional approaches to implement CAA section 111(d) while maintaining reliable, affordable electricity.
Agency officials engaged with community groups representing vulnerable communities, and faith-based groups, among others, during the outreach effort. In response to a request from communities, the EPA held a day-long training on the Clean Power Plan on October 30, 2014, in Washington DC At this meeting, the EPA met with a number of environmental groups to provide information on how the agency plans on reducing carbon pollution from existing power plants using CAA section 111(d).
Many environmental organizations discussed the need for reducing carbon pollution. Meetings were technical, policy and legal in nature and many groups discussed specific state policies that are already in place to reduce carbon pollution in the states.
A number of organizations representing religious groups have reached out to the EPA on several occasions to discuss their concerns and ideas regarding this rule. Many members of faith communities attended the four public hearings.
Public health groups discussed the need for protection of children's health from harmful air pollution. Doctors and health care providers discussed the link between reducing carbon pollution and air pollution and public health. Consumer groups representing advocates for low income electricity customers discussed the need for affordable electricity. They talked about reducing electricity prices for consumers through EE and low-cost carbon reductions.
In winter/spring 2015, EPA continued to offer webinars and teleconferences for community groups on the rulemaking.
Agency officials engaged with environmental justice groups representing communities of color, low-income communities and others during the outreach effort. Agency officials also engaged with the EPA's National Environmental Justice Advisory Council (NEJAC) members in September 2013. The NEJAC is composed of stakeholders, including environmental justice leaders and other leaders from state and local government and the private sector. Additionally, the agency conducted a community call on February 26, 2015, and on February 27, 2015, the EPA conducted a follow up webinar for participants in an October 30, 2014 training session. The EPA also held a webinar for communities on the Clean Air Act (CAA) and section 111(d) of the CAA on April 2, 2015. The agency, in partnership with FERC and DOE, held two additional webinars for communities on the electricity grid and on energy markets on June 11, 2015, and July 9, 2015.
During the EPA's extensive outreach conducted before and after proposal, the EPA has heard a variety of issues raised by environmental justice communities. Communities expressed the desire for the agency to conduct an environmental justice (EJ) analysis and to require that states in the development of their state plans conduct one as well. Additionally, they asked that the agency require that states engage with communities in the development of their state plans and that the agency conduct meaningful involvement with communities, throughout the whole rulemaking process, including the implementation phase. Furthermore, communities stressed the importance of low-income and communities of color receiving the benefits of this rulemaking and being protected from being adversely impacted by this rulemaking.
The purpose of this rule is to substantially reduce emissions of CO
Senior agency officials met with a number of labor union representatives about reducing carbon pollution using CAA section 111(d). Those unions included: The United Mine Workers of America; the Sheet Metal, Air, Rail and Transportation Union (SMART); the
EPA officials attended meetings sponsored by labor unions to give presentations and engage in discussions about reducing carbon pollution using CAA section 111(d). These included meetings sponsored by the IBB and the IBEW.
Throughout the development of the rulemaking, the EPA consulted with other federal agencies with relevant expertise. For example, the EPA met with managers from the U.S. Department of Agriculture's (USDA's) Rural Utility Service to discuss the rule and potential effects on affected EGUs in rural areas and how USDA programs could interact with affected EGUs during rule implementation.
The U.S. Department of Energy (DOE) was a frequent source of expertise on the proposed and final rule. EPA management and staff had numerous meetings with management and staff at DOE on a range of topics, including the effectiveness and costs of energy generation technologies, and EE.
DOE provided technical assistance relating to RE and demand-side EE, including RE and demand-side EE cost and performance data and, for RE, information on the feasibility of deploying and reliably integrating increased RE generation. Further, EPA and DOE staff discussed emission measurement and verification (EM&V) strategies.
The EPA also consulted with DOE on electric reliability issues. EPA staff and managers met and spoke with DOE staff and managers throughout the development of the proposed and final rules on topic related to electric system reliability.
EPA officials worked closely with DOE and Federal Energy Regulatory Commission (FERC) officials to ensure, to the greatest extent possible, that actions taken by states and affected EGUs to comply with the final rule mitigate potential electric system reliability issues. Senior EPA officials met with each of the FERC Commissioners and EPA staff had frequent contact with FERC staff throughout the development the rule. FERC held four technical conferences to discuss implications of compliance approaches to the rule for electric reliability. EPA staff attended the four conferences and EPA leadership spoke at all of them. The EPA, DOE, and FERC will continue to work together to ensure electric grid reliability in the development and implementation of state plans.
The Administrator signed the proposed emission guidelines on June 2, 2014, and, on the same day, the EPA made this version available to the public at
The EPA received more than 4.2 million comments on the proposed carbon pollution emission guidelines from a range of stakeholders that included, including state environmental and energy officials, local government officials, tribal officials, public utility commissioners, system operators, utilities, public interest advocates, and members of the public. The agency received comments on many aspects of the proposal and many suggestions for changes that would address issues of concern.
The EPA is establishing emission guidelines for states to use in developing plans to address GHG emissions from existing fossil fuel-fired electric generating units. The emission guidelines are based on the EPA's determination of the “best system of emission reduction . . . adequately demonstrated” (BSER) and include source category-specific CO
Under CAA section 111(d), the states must establish standards of performance that reflect the degree of emission limitation achievable through the application of the “best system of emission reduction” that, taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements, the Administrator determines has been adequately demonstrated.
The EPA has determined that the BSER is the combination of emission rate improvements and limitations on overall emissions at affected EGUs that can be accomplished through the following three sets of measures or building blocks:
1. Improving heat rate at affected coal-fired steam EGUs.
2. Substituting increased generation from lower-emitting existing natural gas combined cycle units for generation from higher-emitting affected steam generating units.
3. Substituting increased generation from new zero-emitting RE generating capacity for generation from affected fossil fuel-fired generating units.
Consistent with CAA section 111(d) and other rules promulgated under this section, the EPA is taking a traditional, performance-based approach to establishing emission guidelines for affected sources and applying the BSER to two source subcategories of existing fossil fuel-fired EGUs—fossil fuel-fired electric utility steam generating units and stationary combustion turbines. The EPA is finalizing source subcategory-specific emission performance rates that reflect the EPA's application of the BSER. For fossil fuel-fired steam generating units, we are finalizing a performance rate of 1,305 lb CO
Under CAA section 111(d), each state must develop, adopt, and then submit its plan to the EPA. For its CAA section 111(d) plan, a state will determine whether to apply these emission performance rates to each affected EGU, individually or together, or to take an alternative approach and meet either an equivalent statewide rate-based goal or an equivalent statewide mass-based
States with one or more affected EGUs will be required to develop and implement plans that set emission standards for affected EGUs. The CAA section 111(d) emission guidelines that the EPA is promulgating in this action apply to only the 48 contiguous states and any Indian tribe that has been approved by the EPA pursuant to 40 CFR 49.9 as eligible to develop and implement a CAA section 111(d) plan.
In developing its CAA section 111(d) plan, a state will have the option of choosing from two different approaches: (1) An “emission standards” approach, or (2) a “state measures” approach. With an emission standards approach, a state will apply all requirements for achieving the subcategory-specific CO
The EPA is requiring states to make their final plan submittals by September 6, 2016, or to make an initial submittal by this date in order to obtain an extension for making their final plan submittals no later than September 6, 2018, which is 3 years from the signature date of the rule. In order to receive an extension, states, in the initial submittal, must address three required components sufficiently to demonstrate that a state is able to undertake steps and processes necessary to timely submit a final plan by the extended date of September 6, 2018. The first required component is identification of final plan approach or approaches under consideration, including a description of progress made to date. The second required component is an appropriate explanation for why the state requires additional time to submit a final plan beyond September 6, 2016. The third required component for states to address in the initial submittal is a demonstration of how they have been engaging with the public, including vulnerable communities, and a description of how they intend to meaningfully engage with community stakeholders during the additional time (if an extension is granted) for development of the final plan.
Affected EGUs must achieve the final emission performance rates or equivalent state goals by 2030 and maintain that level thereafter. The EPA is establishing an 8-year interim period over which states must achieve the full required reductions to meet the CO
For the final emission guidelines, the EPA is revising the list of components required in a final state plan submittal to reflect: (1) Components required for all state plan submittals; (2) components required for the emission standards approach; and (3) components required for the state measures approach. The revised list of components also reflects the approvability criteria, which are no longer separate from the state plan submittal components.
All state plans must include the following components:
Also, in all state plans, as part of the supporting documentation, a state must include a description of how they considered reliability in developing its state plan.
State plan submittals using the emission standards approach must also include:
• Identification of each affected EGU; identification of federally enforceable emission standards for the affected EGUs; and monitoring, recordkeeping and reporting requirements.
• Demonstrations that each emission standard will result in reductions that are quantifiable, non-duplicative, permanent, verifiable, and enforceable.
State plan submittals using the state measures approach must also include:
• Identification of each affected EGU; identification of federally enforceable emission standards for affected EGUs (if applicable); identification of backstop of federally enforceable emission standards; and monitoring, recordkeeping and reporting requirements.
• Identification of each state measure and demonstration that each state measure will result in reductions that are quantifiable, non-duplicative, permanent, verifiable, and enforceable.
In addition to these requirements, each state plan must follow the EPA implementing regulations at 40 CFR 60.23.
If a state with affected EGUs does not submit a plan or if the EPA does not approve a state's plan, then under CAA section 111(d)(2)(A), the EPA must establish a plan for that state. A state that has no affected EGUs must document this in a formal negative declaration submitted to the EPA by September 6, 2016. In the case of a tribe that has one or more affected EGUs in its area of Indian country,
During implementation of its approved state plan, each state must demonstrate to the EPA that its affected EGUs are meeting the interim and final performance requirements included in this final rule through monitoring and reporting requirements. State plan requirements and flexibilities are described more fully in Section VIII of this preamble.
This rule is consistent with the requirements of CAA section 111(d) and the implementing regulations.
A key step in promulgating requirements under CAA section 111(d)(1) is determining the “best system of emission reduction which . . . the Administrator determines has been adequately demonstrated” (BSER) under CAA section 111(a)(1). It is clear by the terms of section 111(a)(1) and the implementing regulations for section 111(d) that the EPA is authorized to determine the BSER;
The EPA is finalizing the BSER for fossil fuel-fired EGUs based on building blocks 1, 2, and 3. Building block 1 includes operational improvements and equipment upgrades that the coal-fired steam-generating EGUs in the state may undertake to improve their heat rate. It qualifies as part of the BSER because it improves the carbon intensity of the affected EGUs in generating electricity through actions the affected sources may undertake that are adequately demonstrated and whose cost is “reasonable.” Building blocks 2 and 3 include increases in low- or zero-emitting generation which substitute for generation from the affected EGUs and thereby reduce CO
Building blocks 2 and 3 may be implemented through a set of measures, including reduced generation from the fossil fuel-fired EGUs. These measures do not, however, reduce the amount of electricity that can be sold or that is available to end users. In addition, states should be expected to allow their affected EGUs to trade rate-based emission credits or mass-based emission allowances (trading) because trading is well-established for this industry and has the effect of focusing costs on the affected EGUs for which reducing emissions is most cost-effective. Because trading facilitates implementation of the building blocks and may help to optimize cost-effectiveness, trading is a method of implementing the BSER as well.
As a result, an affected EGU has a set of choices for achieving its emission standards. For example, an affected coal-fired steam generating unit can achieve a rate-based standard through a set of actions that implement the building block 1 measures and that implement the building block 2 and 3 measures through a set of actions that range from purchasing full or partial interest in existing NGCC or new RE assets to purchasing ERCs that represent the environmental attributes of increased NGCC generation or new renewable generation. In addition, the affected EGU may reduce its generation and thereby reduce the extent that it needs to implement the building blocks. The affected EGU may also purchase rate-based emission credits from other affected EGUs. If the state chooses to impose a mass-based emission standard, the coal-fired steam generating unit may implement building block 1 measures, purchase mass-based emission allowances from other affected EGUs, or reduce its generation. In light of the available sources of lower- and zero-emitting replacement generation, this approach would achieve an appropriate level of emission reductions and maintain the reliability of the electricity system.
With the promulgation of the emission guidelines, each state must develop and submit a plan to achieve the CO
These two types of state plans and their respective approaches, which could be implemented on a single-state or multi-state basis, allow states to meet the statutory requirements of section 111(d) while accommodating the wide range of regulatory requirements and other programs that states have deployed or will deploy in the electricity sector that reduce CO
Both state plan types, and the standards of performance for the affected EGUs that the states will establish through the state plan process, are consistent with the applicable CAA section 111 provisions. A state has discretion in determining the appropriate measures to rely upon for its plan. The state may adopt measures that assure the achievement of the requisite CO
In this rulemaking, the EPA establishes reasonable deadlines for state plan submission. Under CAA section 111(d)(1), state plans must “provide for implementation and enforcement” of the standards of performance, and under CAA section 111(d)(2), the state plans must be “satisfactory” for the EPA to approve them. In this rulemaking, the EPA is finalizing the criteria that the state plans must meet under these requirements.
The EPA discusses its legal interpretation in more detail in other parts of this preamble and provides additional information about certain issues in the Legal Memorandum included in the docket for this rulemaking.
EPA's authority for this rule is CAA section 111(d). CAA section 111(d) provides that the EPA will promulgate regulations under which each state will establish standards of performance for existing sources for any air pollutant that meets two criteria. First, CAA section 111(d) applies to air pollutants that are not regulated as a criteria pollutant under section 108 or as a hazardous air pollutant (HAP) under CAA section 112. 42 U.S.C. 7411(d)(1)(A)(i).
CAA section 111(d) contains an exclusion that limits the regulation under CAA section 111(d) of air pollutants that are regulated under CAA section 112. 42 U.S.C. 7411(d)(1)(A)(i). This “Section 112 Exclusion” in CAA section 111(d) was the subject of a significant number of comments based on two differing amendments to this exclusion enacted in the 1990 CAA Amendments. As discussed in more detail below, the House and the Senate each initially passed different amendments to the Section 112 Exclusion and both amendments were ultimately passed by both houses and signed into law. In 2005, in connection with the Clean Air Mercury Rule (CAMR), the EPA discussed the agency's interpretation of the Section 112 Exclusion in light of these two differing amendments and concluded that the two amendments were in conflict and that the provision should be read as follows to give both amendments meaning: where a source category has been regulated under CAA section 112, a CAA section 111(d) standard of performance cannot be established to address any HAP listed under CAA section 112(b) that may be emitted from that particular source category. See 70 FR 15994, 16029-32 (March 29, 2005).
In June 2014, the EPA presented this previous interpretation as part of the proposal and requested comment on it. The EPA received numerous comments on its previous interpretation, including comments on the proper interpretation and effect of each of the two differing amendments, and whether the Section 112 Exclusion should be read to mean that the EPA's regulation of HAP from power plants under CAA section 112 bars the EPA from establishing CAA section 111(d) regulations covering CO
In light of the comments, the EPA has reconsidered its previous interpretation of the Section 112 Exclusion and, in particular, considered whether the exclusion precludes the regulation under CAA section 111(d) of CO
The Clean Air Act sets out a comprehensive scheme for air pollution control, addressing three general categories of pollutants emitted from stationary sources: (1) Criteria pollutants (which are addressed in sections 108-110); (2) hazardous pollutants (which are addressed under section 112); and (3) “pollutants that are (or may be) harmful to public health or welfare but are not or cannot be controlled under sections 108-110 or 112.” 40 FR 53340 (Nov. 17, 1975).
Six “criteria” pollutants are regulated under sections 108-110. These are pollutants that the Administrator has concluded “cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare;” “the presence of which in the ambient air results from numerous and diverse mobile or stationary sources;” and for which the Administrator has issued, or plans to issue, “air quality criteria. 42 U.S.C. 7408(a)(1). Once the EPA issues air quality criteria for such pollutants, the Administrator must propose primary National Ambient Air Quality Standards (NAAQS) for them, set at levels “requisite to protect the public health” with an “adequate margin of safety.” 42 U.S.C. 7409(a)-(b). States must then adopt plans for implementing NAAQS. 42 U.S.C. 7410.
HAP are regulated under CAA section 112 and include the pollutants listed by Congress in section 112(b)(1) and other pollutants that the EPA lists under sections 112(b)(2) and (b)(3). CAA section 112 further provides that the EPA will publish and revise a list of “major” and “area” source categories of HAP, and then establish emissions standards for HAP emitted by sources within each listed category. 42 U.S.C. 7412(c)(1) & (2).
CAA section 111, 42 U.S.C. 7411, is the third part of the CAA's structure for regulating stationary sources. Section 111 has two main components. First, section 111(b) requires the EPA to promulgate federal “standards of performance” addressing
Together, the criteria pollutant/NAAQS provisions in sections 108-110, the hazardous air pollutant provisions in section 112, and performance standard provisions in section 111 constitute a comprehensive scheme to regulate air pollutants with “no gaps in control activities pertaining to stationary source emissions that pose any significant danger to public health or welfare.” S. Rep. No. 91-1196, at 20 (1970).
The specific role of CAA section 111(d) in this structure can be seen in CAA subsection 111(d)(1)(A)(i), which provides that regulation under CAA section 111(d) is intended to cover pollutants that are not regulated under either the criteria pollutant/NAAQS provisions or section 112. Prior to 1990, this limitation was laid out in plain language, which stated that CAA section 111(d) regulation applied to “any air pollutant . . . for which air quality criteria have not been issued or which is not included on a list published under section [108(a)] or [112(b)(1)(A)].” This plain language demonstrated that section 111(d) is designed to regulate pollutants from existing sources that fall in the gap not covered by the criteria pollutant provisions or the hazardous air pollutant provisions.
This gap-filling purpose can be seen in the early legislative history of the CAA. As originally enacted in the 1970 CAA, the precursor to CAA section 111 (which was originally section 114) was described as covering pollutants that would not be controlled by the criteria pollutant provisions or the hazardous air pollutant provisions. See S. Committee Rep. to accompany S. 4358 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 420 (“It should be noted that the emission standards for pollutants which cannot be considered hazardous (as defined in section 115 [which later became section 112]) could be established under section 114 [later, section 111]. Thus, there should be no gaps in control activities pertaining to stationary source emissions that pose any significant danger to public health or welfare.”); Statement by S. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 227 (“[T]he bill [in section 114] provides the Secretary with the authority to set emission standards for selected pollutants which cannot be controlled through the ambient air quality standards and which are not hazardous substances.”).
The Act was amended extensively in 1990. Among other things, Congress sought to accelerate the EPA's regulation of hazardous pollutants under section 112. To that end, Congress established a lengthy list of HAP; set criteria for listing “source categories” of such pollutants; and required the EPA to establish standards for each listed source category's hazardous pollutant emissions. 42 U.S.C. 7412(b), (c) and (d). In the course of overhauling the regulation of HAP under section 112, Congress needed to edit section 111(d)'s reference to section 112(b)(1)(A), which was to be eliminated as part of the revisions to section 112.
To address the obsolete cross-reference to section 7412(b)(1)(A), Congress passed two differing amendments—one from the Senate and one from the House—that were never reconciled in conference. The Senate amendment replaced the cross reference to old section 112(b)(1)(A) with a cross-reference to new section 112. Pub. L. 101-549, § 302(a), 104 Stat. 2399, 2574 (1990). The House amendment replaced the cross-reference with the phrase “emitted from a source category which is regulated under section [112].” Pub. L. 101-549, § 108(g), 104 Stat. 2399, 2467 (1990).
Unlike the ambiguous amendment to CAA section 111(d) in the House amendment (discussed below), the Senate amendment is straightforward and unambiguous. It maintained the pre-1990 meaning of the Section 112 Exclusion by simply substituting “section 112(b)” for the prior cross-reference to “section 112(b)(1)(A).” Pub. L. 101-549, § 302(a), 104 Stat. 2399, 2574 (1990). So amended, CAA section 111(d) mandates that the EPA require states to submit plans establishing standards for “any air pollutant . . . which is not included on a list published under section [108(a)] or section [112(b)].” Thus, the Section 112 Exclusion resulting from the Senate amendment would preclude CAA section 111(d) regulation of HAP emission but would not preclude CAA section 111(d) regulation of CO
Some commenters have argued that the Senate amendment should be given no effect, because only the House amendment is shown in the U.S. Code, and because the Senate amendment appeared under the heading “conforming amendments,” and for various other reasons. The EPA disagrees. The Senate amendment, like the House amendment, was enacted into law as part of the 1990 CAA amendments, and must be given effect.
First, that the U.S. Code only reflects the House amendment does not change the fact that both amendments were signed into law as part of the 1990 Amendments, as shown in the Statutes at Large. Pub. L. 101-549, §§ 108(g) and 302(a), 104 Stat. 2399, 2467, 2574 (1990). Where there is a conflict between the U.S. Code and the Statutes at Large, the latter controls. See 1 U.S.C. 112 & 204(a);
Second, the “conforming” label is irrelevant. A “conforming” amendment may be either substantive or non-substantive.
Third, the legislative history of the Senate amendment supports the conclusion that the substitution of the updated cross-reference was not a mindless, ministerial decision, but reflected a decision to choose an update of the cross reference instead of the text that was inserted into the Section 112 Exclusion by the House amendment. In mid-1989, the House and Senate introduced identical bills (H.R. 3030 and S. 1490, respectively) to provide for “miscellaneous” changes to the CAA. In both the Senate and House bills as they were introduced in mid-1989, the Section 112 Exclusion was to be amended by taking out “or 112(b)(1)(A)” and inserting “or emitted from a source category which is regulated under section 112.” H.R. 3030, as introduced, 101st Cong. § 108 (Jul. 27, 1989); S. 1490, as introduced, 101st Cong. § 108 (Aug. 3, 1989). See 1990 CAA Legis. Hist. at 3857 (noting that H.R. 3030 and S.1490, as introduced, were the same). Although S. 1490 was identical to H.R. 3030 when they were introduced, the Senate reported a vastly different bill (S.1630) at the end of 1989. See
a.
Further, a proper reading of statutory text “must employ all the tools of statutory interpretation, including text, structure, purpose, and legislative history.”
“We do not lightly presume that Congress has legislated in self-contradicting terms. See A. Scalia & B. Garner, Reading Law: The Interpretation of Legal Texts 180 (2012) (“The provisions of a text should be interpreted in a way that renders them compatible, not contradictory. . . . [T]here can be no justification for needlessly rendering provisions in conflict if they can be interpreted harmoniously”). . . . Thus, time and again we have stressed our duty to “fit, if possible, all parts [of a statute] into [a] harmonious whole.”
As amended by the House, CAA section 111(d)(1)(A)(i) limits CAA section 111(d) to any air pollutant “for which air quality criteria have not been issued or which is not included on a list published under section 7408(a) of this title or emitted from a source category which is regulated under section 7412 of this title . . .” This statutory text is ambiguous and subject to numerous possible readings.
First, the text of the House-amended version of CAA section 111(d) could be read literally as authorizing the regulation of any pollutant that is not a criteria pollutant. This reading arises if one focuses on the use of “or” to join the three clauses:
The Administrator shall prescribe regulations . . . under which each State shall submit to the Administrator a plan which establishes standards of performance for any existing source for any air pollutant [1] for which air quality criteria have not been issued or [2] which is not included on a list published under section 7408(a) of this title or [3] emitted from a source category which is regulated under section 7412 of this title. . . .
42 U.S.C. 7411(d)(1) (emphasis and internal numbering added). Because the text contains the conjunction “or” rather than “and” between the three clauses, a literal reading could read the three clauses as alternatives, rather than requirements to be imposed simultaneously. In other words, a literal reading of the language of section 111(d) provides that the Administrator may require states to establish standards for an air pollutant so long as
A second reading of CAA section 111(d) as revised by the House amendment focuses on the lack of a negative before the third clause. That is, unlike the first and second clauses that each contain negative phrases (either “has not been issued” or “which is not included”), the third clause does not. One could presume that the negative from the second clause was intended to carry over, implicitly inserting another “which is not” before “emitted from a source category which is regulated under section [112].” But that is a presumption, and not the plain language of the statute. The text as amended by the House says that the EPA “shall” prescribe regulations for “any air pollutant . . . emitted from a source category which is regulated under section [112].” 42 U.S.C. 7411(d)(1). Thus, CAA section 111(d)(1)(A)(i) could be read as providing for the regulation of emissions of pollutants if they are emitted from a source category that is regulated under CAA section 112. Like the first reading discussed above, this reading would authorize the regulation of CO
If one does presume that the “which is not” phrase is intended to carry over to the third clause, then CAA section 111(d) regulation under the House amendment would be limited to “any air pollutant . . . which is not . . . emitted from a source category which is regulated under section [112].” Even with this presumption, however, the House amendment contains further ambiguities with respect to the phrases “a source category” and “regulated under section 112,” and how those phrases are used within the structure of the provision limiting what air pollutants may be regulated under CAA section 111(d).
The phrase “regulated under section 112” is ambiguous. As the Supreme Court has explained in the context of other statutes using a variation of the word “regulate,” an agency must consider what is being regulated. See
Under this reading, and assuming the phrase “a source category” is read to mean the particular source category, the House amendment would preclude the regulation under CAA section 111(d) of a specific source category for any pollutant if that source category has been regulated for any HAP under CAA section 112.
Further, some supporters of this interpretation have suggested that EPA could regulate CO
b.
The EPA's interpretation of the House amendment as applied to the issue presented in this rule is that the Section 112 Exclusion excludes the regulation of HAP under CAA section 112 if the source category at issue is regulated under CAA section 112, but does not exclude the regulation of other pollutants, regardless of whether that source category is subject to CAA section 112 standards. This interpretation reads the phrase “regulated under section 112” as modifying the words “source category” (as does the interpretation discussed above) but also recognizes that the phrase “regulated under section 112” refers only to the regulation of HAP emissions. In other words, the EPA's interpretation recognizes that source categories “regulated under section 112” are not regulated by CAA section 112 with respect to all pollutants, but only with respect to HAP. Thus, it is reasonable to interpret the House amendment of the Section 112 Exclusion as only excluding the regulation of HAP emissions under CAA section 111(d) and only when that source category is regulated under CAA section 112. We note that this interpretation of the House amendment alone is the same as the 2005 CAMR interpretation of the two amendments combined: Where a source category has been regulated under CAA section 112, a CAA section 111(d) standard of performance cannot be established to address any HAP listed under CAA section 112(b) that may be emitted from that particular source category. See 70 FR 15994, 16029-30 (March 29, 2005).
There are a number of reasons why the EPA's interpretation is reasonable and avoids the issues discussed above.
First, the EPA's interpretation reads the House amendment to the Section 112 Exclusion as determining the scope of what air pollutants are to be regulated under CAA section 111(d), as opposed to creating a wholesale exclusion for source categories. The other text in subsections 111(d)(1)(A)(i) and (ii) modify the phrase “any air pollutant.” Thus, reading the Section 112 Exclusion to also address the question of what air pollutants may be regulated under CAA section 111(d) is consistent with the overall structure and focus of CAA section 111(d)(1)(A).
Second, the EPA's interpretation furthers—rather than undermines—the purpose of CAA section 111(d) within the long-standing structure of the CAA. That is, this interpretation supports the comprehensive structure for regulating various pollutants from existing sources under the criteria pollutant/NAAQS program under sections 108-110, the HAP program under section 112, and other pollutants under section 111(d), and avoids creating a gap in that structure. See
Third, by avoiding the creation of gaps in the statutory structure, the EPA's interpretation is consistent with the legislative history demonstrating that Congress's intent in the 1990 CAA Amendments was to expand the EPA's regulatory authority across the board, compelling the agency to regulate more pollutants, under more programs, more quickly.
Fourth, when applied in the context of this rule, the EPA's interpretation of the House amendment is consistent with the Senate amendment. Thus, this interpretation avoids creating a conflict within the statute. See discussion above of
In sum, when this interpretation of the House amendment is applied in the context of this rule, the result is that the EPA may promulgate CAA section 111(d) regulations covering carbon dioxide emissions from existing power plants notwithstanding that power plants are regulated for their HAP emissions under CAA section 112.
Given that both the House and Senate amendments should be read individually as having the same meaning in the context presented in this rule, giving each amendment full effect is straight-forward: The Section 112 Exclusion in section 111(d) does not foreclose the regulation of non-HAP from a source category regardless of whether that source category is also regulated under CAA section 112. As applied here, the EPA has the authority to promulgate CAA section 111(d) regulations for CO
In a separate, concurrent action, the EPA is also finalizing a CAA section 111(b) rulemaking that regulates CO
CAA section 111(d)(1) requires the EPA to promulgate regulations under which states must submit state plans regulating “any existing source” of certain pollutants “to which a standard of performance would apply if such existing source were a new source.” A “new source” is “any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under [CAA section 111] which will be applicable to such source.” It should be noted that these provisions make clear that a “new source” includes one that undertakes either new construction or a modification. It should also be noted that the EPA's implementing regulations define “construction” to include “reconstruction,” which the implementing regulations go on to define as the replacement of components of an existing facility to an extent that (i) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (ii) it is technologically and economically feasible to meet the applicable standards.
Under CAA section 111(d)(1), in order for existing sources to become subject to that provision, the EPA must promulgate standards of performance under CAA section 111(b) to which, if the existing sources were new sources, they would be subject. Those standards of performance may include standards for sources that undertake new construction, modifications, or reconstructions.
The EPA is finalizing a rulemaking under CAA section 111(b) for CO
For the emission guidelines, an affected EGU is any fossil fuel-fired electric utility steam generating unit (
When considering and understanding applicability, the following definitions may be helpful. Simple cycle combustion turbine means any stationary combustion turbine which does not recover heat from the combustion turbine engine exhaust gases for purposes other than enhancing the performance of the stationary combustion turbine itself. Combined cycle combustion turbine means any stationary combustion turbine which recovers heat from the combustion turbine engine exhaust gases to generate steam that is used to create additional electric power output in a steam turbine. Combined heat and power (CHP) combustion turbine means any stationary combustion turbine which recovers heat from the combustion turbine engine exhaust gases to heat water or another medium, generate steam for useful purposes other than exclusively for additional electric generation, or directly uses the heat in the exhaust gases for a useful purpose.
We note that certain affected EGUs are exempt from inclusion in a state plan. Affected EGUs that may be excluded from a state's plan are (1) those units that are subject to subpart TTTT as a result of commencing modification or reconstruction; (2) steam generating units or IGCC units that are currently and always have been subject to a federally enforceable permit limiting net-electric sales to one-third or less of its potential electric output or 219,000 MWh or less on an annual basis; (3) non-fossil units (
The rationale for applicability of this final rule is multi-fold. We had proposed that affected EGUs were those existing fossil fuel-fired EGUs that met the applicability criteria for coverage under the final GHG standards for new fossil fuel-fired EGUs being promulgated under section 111(b). However, we are finalizing that States need not include certain units that would otherwise meet the CAA section 111(b) applicability in this CAA section 111(d) emission guidelines. These include simple cycle turbines, certain non-fossil units, and certain combined heat and power units. The final 111(b) standards include applicability criteria for simple cycle combustion turbines, for reasons relating to implementation and minimizing emissions from all future combustion turbines. However, for the following reasons none of the building blocks would result in emission reductions from simple cycle turbines so we are not requiring that States including them in their CAA section 111(d) plans.
First, even more than combined cycle units, simple cycle units have limited opportunities, compared to steam generating units, to reduce their heat rate. Most combustion turbines likely already follow the manufacturer's recommended regular preventive/restorative maintenance for both reliable and efficiency reasons. These regularly scheduled maintenance practices are highly effective methods to maintain heat rates, and additional fleet-wide reductions from simple cycle combustion turbines are likely less than 2 percent. In addition, while approximately one-fifth of overall fossil fuel-fired capacity (GW) consists of simple cycle turbines, these units historically have operated at capacity factors of less than 5 percent and only provide about 1 percent of the fossil fuel-fired generation (GWh). Combustion turbine capacity can therefore only contribute CO
Further, we are not aware of an approach to estimate any limited opportunities that existing simple cycle turbines may have to reduce their heat rate. Similar to coal-steam EGUs, we do not have the unit-specific detailed design information on existing individual simple cycle combustion turbines that is necessary for a detailed assessment of the heat rate improvement potential via best practices and upgrades for each unit. While the EPA could conduct a “variability analysis” of simple cycle historical hourly heat rate data (as was done for coal-steam EGUs), the various simple cycle models in use and the historically lower capacity factors of the simple cycle fleet (less run time per start, and more part load operation) would require a simple cycle analysis that includes more complexity and likely more uncertainty than in the coal-steam analysis. Therefore, we do not consider it feasible to estimate potential reductions due to heat rate improvements from simple cycle turbines, and even if it were, we have concluded those reductions would be negligible compared to the reductions from steam generating units. Hence, we do not consider building block 1 as practically applicable to simple cycle units.
Second, the vast majority of simple cycle turbines serve a specific need—providing power during periods of peak electric demand (
Third, many commenters on the CAA section 111(b) proposal stated that simple cycle turbines will be used to provide backup power to intermittent renewable sources of power such as wind and solar. Consequently, adding additional generation from intermittent renewable sources has the potential to actually increase emissions from simple cycle turbines. Therefore, applying building block 3 based on the capacity of simple cycle turbines would not result in emission reductions from simple cycle combustion turbines. Finally, the EPA expects existing simple cycle turbines to continue to operate as they historically have operated, as peaking units. Including simple cycle turbines in CAA section 111(d) applicability would impact the numerical value of state goals, but it would not impact the stringency of the plans. Such inclusion would increase burden but result in no environmental benefit.
Additionally, under CAA section 111(b) final applicability criteria, new dedicated non-fossil and industrial CHP units are not affected sources if they include permit restrictions on the amount of fossil fuel they burn and the amount of electricity they sell. Such units historically have had no regulatory mandate to include permit requirements limiting the use of fossil fuel or electric sales. We are exempting them from inclusion in CAA section 111(d) state plans in the interest of consistency with CAA section 111(b) and based on their historical fuel use and electric sales.
We discuss changes in applicability of units in relation to state plans in Section VIII of this preamble.
In this rulemaking, the EPA is combining the listing of sources from the two existing source categories for the affected EGUs, as listed in 40 CFR subpart Da and 40 CFR subpart KKKK, into a single location, 40 CFR subpart UUUU, for purposes of addressing the CO
We believe that combining the emission guidelines for affected sources into a new subpart UUUU is appropriate because the emission guidelines the EPA is establishing do not vary by type of source. Combining the listing of sources into one location, subpart UUUU, will facilitate implementation of CO
As discussed in the January 8, 2014 proposal for the CAA section 111(b) standards for GHG emissions from EGUs (79 FR 1430), in 1971 the EPA listed fossil fuel-fired steam generating boilers as a new category subject to section 111 rulemaking, and in 1979 the EPA listed fossil fuel-fired combustion turbines as a new category subject to the CAA section 111 rulemaking. In the ensuing years, the EPA has promulgated standards of performance for the two categories and codified those standards, at various times, in 40 CFR part 60 subparts D, Da, GG, and KKKK.
In the January 8, 2014 proposal, the EPA proposed separate standards of performance for new sources in the two categories and proposed codifying the standards in the same Da and KKKK subparts that currently contain the standards of performance for conventional pollutants from those sources. In addition, the EPA co-proposed combining the two categories into a single category solely for purposes of the CO
In this rulemaking, the EPA is combining the two listed source categories into a single source category for purposes of the emission guidelines for the CO
In the June 2014 proposal, the EPA proposed to determine that the best system of emission reduction adequately demonstrated (BSER) for reducing CO
Consistent with the approach taken in the proposed rule, in determining the BSER we have taken account of the unique characteristics of CO
With attention to emission reduction costs, electricity rates, and the importance of ensuring continued reliability of electricity supplies, the individual building blocks and the overall BSER have been defined not at the maximum possible degree of stringency but at a reasonable degree of stringency designed to appropriately balance consideration of the various BSER factors. Additional, non-building block-specific aspects of the BSER quantification methodology discussed below are similarly mindful of these considerations. This approach to determination of the BSER provides compliance headroom that ensures that the emission limitations reflecting the BSER are achievable by the source category, but nevertheless, as required by the CAA, will result in meaningful reductions in CO
The final BSER incorporates certain changes from the proposed rule, reflecting the EPA's consideration of comments responding to the approaches outlined in the proposal and our own further analysis. The principal changes are the exclusion from the BSER of emission reductions achievable through demand-side EE and through nuclear generation; a revised approach to determination of emission reductions achievable through increased RE generation; a consistent approach to determination of emission reductions achievable through all the building blocks that better reflects the regional nature of the electricity system and entails separate analyses for the Eastern, Western, and Texas Interconnections; and a revised interim goal period of 2022 to 2029 (instead of the proposed interim period of 2020 to 2029). These changes to the BSER and the building blocks are discussed in more detail later in this section of the preamble.
Also, to address concerns identified in the proposal and the October 30, 2014 NODA and in response to associated comments, in the final rule we have represented the emission limitations achievable through the BSER in the form of uniform CO
Section V.A. describes our determination of the final BSER, including a discussion of the associated emissions performance level, and provides the rationale for our determination. In section V.B. we address certain legal issues in greater detail, including key issues raised in comments. Sections V.C. through V.E. contain more detailed discussions of the three individual building blocks included in the final BSER. Further information can be found in the GHG Mitigation Measures TSD for the CPP Final Rule, the CO
This section sets forth our determination of the BSER for reducing CO
a.
We received comments on our proposed interpretation, and in light of those comments, in this final rule, we are clarifying our interpretation in certain respects. We discuss our interpretation below.
b.
The term “standard of performance” is defined to mean—
These provisions authorize the EPA to determine the BSER for the affected sources and, based on the BSER, to establish emission guidelines that identify the minimum amount of emission limitation that a state, in its state plan, must impose on its sources through standards of performance. Consistent with these CAA requirements, the EPA's regulations require that the EPA's guidelines reflect—
The EPA's approach in this rulemaking is to determine the BSER on a source subcategory-wide basis, to determine the emission limitation that results from applying the BSER to the sources in the subcategory, and then to establish emission guidelines for the states that incorporate those emission limitations. The EPA expresses these emission limitations in the form of emission performance rates, and they must be achievable by the source subcategory through the application of the BSER.
Following the EPA's promulgation of emission guidelines, each state must determine the standards of performance for its sources, which the EPA's regulations call “designated facilities.”
As noted in the January 2014 proposal and discussed in more detail above under section II.G, Congress first included the definition of “standard of performance” when enacting CAA section 111 in the 1970 Clean Air Act Amendments (CAAA), amended it in the 1977 CAAA, and then amended it again in the 1990 CAAA to largely restore the definition as it read in the 1970 CAAA. It is in the legislative history for the 1970 and 1977 CAAA that Congress primarily addressed the definition as it read at those times and that legislative history provides guidance in interpreting this provision.
a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction) the Administrator determines has been adequately demonstrated.
In the 1977 CAAA, Congress revised the definition to distinguish among different types of sources, and to require that for fossil fuel-fired sources, the standard (i) be based on, in lieu of the “best system of emission reduction . . . adequately demonstrated,” the “best technological system of continuous emission reduction . . . adequately demonstrated;” and (ii) require a percentage reduction in emissions. In addition, in the 1977 CAAA, Congress expanded the parenthetical requirement that the Administrator consider the cost of achieving the reduction to also require the Administrator to consider “any nonair quality health and environmental impact and energy requirements.”
In the 1990 CAAA, Congress again revised the definition, this time repealing the requirements that the standard of performance be based on the best technological system and achieve a percentage reduction in emissions, and replacing those provisions with the terms used in the 1970 CAAA version of § 111(a)(1) that the standard of performance be based on the “best system of emission reduction . . . adequately demonstrated.” This 1990 CAAA version is the current definition, which is applicable at present. Even so, because parts of the definition as it read under the 1977 CAAA were retained in the 1990 CAAA, the explanation in the 1977 CAAA legislative history, and the interpretation, in the case law, of those parts of the definition remain relevant to the definition as it reads today.
c.
Our overall approach to determining the BSER and emission guidelines, which incorporates the various elements, is as follows: In developing an emission guideline, we generally engage in an analytical approach that is similar to what we conduct under CAA section 111(b) for new sources. First, we identify “system[s] of emission reduction” that have been “adequately demonstrated” for a particular source category. Second, we determine the “best” of these systems after evaluating the amount of reductions, costs, any nonair health and environmental impacts, energy requirements, and, in the alternative, the advancement of technology (that is, we apply a formulation of the BSER with the above noted factors, and then, in the alternative, we apply a formulation of the BSER with those same factors plus the advancement of technology). And third, we select an achievable emission limit—here, the emission performance rates—based on the BSER.
The remainder of this subsection discusses the various elements in our general analytical approach.
As we discuss below, the CAA does not define the phrase “system of emission reduction.” The ordinary, everyday meaning of “system” is a set of things or parts forming a complex whole; a set of principles or procedures according to which something is done; an organized scheme or method; and a group of interacting, interrelated, or interdependent elements.
Under section 111(a)(1), in order for a “system of emission reduction” to serve as the basis for an “achievable” emission limitation, the Administrator must determine that the system is “adequately demonstrated.” This means, according to the D.C. Circuit, that the system is “one which has been shown to be reasonably reliable, reasonably efficient, and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.”
In determining which adequately demonstrated system of emission reduction is the “best,” the EPA considers the following factors:
Under CAA section 111(a)(1), the EPA is required to take into account “the cost of achieving” the required emission reductions. As described in the January 2014 proposal,
In the [1970] Congress [
1977 House Committee Report at 184. Similarly, the 1970 Senate Committee Report stated:
The implicit consideration of economic factors in determining whether technology is “available” should not affect the usefulness of this section. The overriding purpose of this section would be to prevent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach.
S. Comm. Rep. No. 91-1196 at 16.
The D.C. Circuit has repeatedly upheld the EPA's consideration of cost in reviewing standards of performance. In several cases, the Court upheld standards that entailed significant costs, consistent with Congress's view that “the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business.”
As discussed below, the EPA may consider costs on both a source-specific basis and a sector-wide, regional, or nationwide basis.
Under CAA section 111(a)(1), the EPA is required to take into account “any nonair quality health and environmental impact” in determining the BSER. As the D.C. Circuit has explained, this requirement makes explicit that a system cannot be “best” if it does more harm than good due to cross-media environmental impacts.
Under CAA section 111(a)(1), the EPA is required to take into account “energy requirements.” As discussed below, the EPA may consider energy requirements on both a source-specific basis and a sector-wide, region-wide, or nationwide basis. Considered on a source-specific basis, “energy requirements” entails, for example, the impact, if any, of the system of emission reduction on the source's own energy needs.
In the proposed rulemakings for this rule and the associated section 111(b) rule, we noted that although the definition of “standard of performance” does not by its terms identify the amount of emissions from the category of sources or the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” the D.C. Circuit has stated that the EPA must do so.
As discussed in the January 2014 proposal for the section 111(b) rulemaking and the proposal for this rulemaking, another component of the D.C. Circuit's interpretations of CAA section 111 is that the EPA may consider the various factors it is required to consider on a national or regional level and over time, and not only on a plant-specific level at the time of the rulemaking.
[T]he Reports from both Houses on the Senate and House bills illustrate very clearly that Congress itself was using a long-term lens with a broad focus on future costs, environmental and energy effects of different technological systems when it discussed section 111.
The standard reflects a balance in environmental, economic, and energy consideration by being sufficiently stringent to bring about substantial reductions in SO
By substantially reducing SO
In this rule, the EPA is considering costs and energy implications on the
Before discussing the requirement under section 111(d) that the emission limitation in the emission guidelines must be “achievable,” it is useful to discuss the comparable requirement under section 111(b) for new sources. For new sources, CAA section 111(b)(1)(B) and (a)(1) provides that the EPA must establish “standards of performance,” which are standards for emissions that reflect the degree of emission limitation that is “achievable” through the application of the BSER. According to the D.C. Circuit, a standard of performance is “achievable” if a technology can reasonably be projected to be available to an individual source at the time it is constructed that will allow it to meet the standard.
The D.C. Circuit established these standards for achievability in cases concerning CAA section 111(b) new source standards of performance. There is no case law under CAA section 111(d). Assuming that those standards for achievability apply under section 111(d), in this rulemaking, we are taking a similar approach for the emission limitation that the EPA identifies in the emission guidelines. For existing sources, section 111(d)(1) requires the EPA to establish requirements for state plans that, in turn, must include “standards of performance.” Through long-standing regulations
The EPA has promulgated these emission guidelines on the basis that the existing sources can achieve the limitation, even though the state retains discretion to apply standards of performance to individual sources that are more or less stringent.
As indicated in the proposed rulemakings for this rule and the associated section 111(b) rule, the requirement that the emission limitation in the emission guidelines be “achievable” based on the “best system of emission reduction . . . adequately demonstrated” indicates that the technology or other measures that the EPA identifies as the BSER must be technically feasible.
The D.C. Circuit has long held that Congress intended for CAA section 111 to create incentives for new technology and therefore that the EPA is required to consider technological innovation as one of the factors in determining the “best system of emission reduction.”
In any event, as discussed below, the EPA may justify the control measures identified in this rule as the BSER even without considering the factor of incentivizing technological innovation or development.
The D.C. Circuit has made clear that the EPA has broad discretion in determining the appropriate standard of performance under the definition in CAA section 111(a)(1), quoted above. Specifically, in
Because section 111 does not set forth the weight that should be assigned to each of these factors, we have granted the agency a great degree of discretion in balancing them. . . . EPA's choice [of the `best system'] will be sustained unless the environmental or economic costs of using the technology are exorbitant. . . . EPA [has] considerable discretion under section 111.
d.
As with any of its own regulations, the EPA has authority to interpret or revise these regulations.
Of course, regardless of whether the EPA subcategorizes within a source category for purposes of determining the BSER and the emissions performance level for the emission guideline, as part of its CAA section 111(d) plan, a state retains great flexibility in assigning standards of performance to its affected EGUs. Thus, the state may, if it wishes, impose different emission reduction obligations on different sources, as long as the overall level of emission limitation is at least as stringent as the emission guidelines.
a.
In establishing the BSER the EPA also considered the set of actions that an EGU, operating under a standard of performance established by its state, may take to achieve the applicable performance rate, if the state adopts that rate as the standard of performance and applies it to the EGUs in its jurisdiction, or to achieve the equivalent mass-based limit, and that meet the other requirements for the BSER. These actions implement the BSER and may therefore be understood as part of the BSER.
An example illustrating the relationship between the measures determined to constitute the BSER for the source category and the actions that may be undertaken by individual sources that are therefore also part of the BSER is the substitution of zero-emitting generation for CO
To reiterate the overall context for the BSER: In this rule, the EPA determined the BSER, and applied it to the category of affected EGUs to determine the performance levels—that is, the CO
This section describes the EPA's process and basis for determining the BSER for the purpose of determining the CO
The set of measures identified as the BSER for the source category encompasses a menu of actions that are part of the BSER and that individual affected EGUs may implement in different amounts and combinations in order to achieve their emission limits at reasonable cost. This menu includes actions that: (i) Affected steam EGUs can implement to improve their heat rates; (ii) affected steam EGUs can implement to increase generation from lower-emitting existing NGCC units in specified amounts; (iii) all affected EGUs can implement to increase generation from new low- or zero-carbon generation sources in specified amounts; (iv) all affected EGUs can implement to reduce their generation in specified amounts; and (v) all affected EGUs operating under a standard of performance that incorporates emissions trading can implement by means of purchasing rate-based emission credits or mass-based emission allowances from other affected EGUs, since the effect of the purchase would be the same as achieving the other listed actions through direct means.
Importantly, affected EGUs also have available numerous other measures that are not included in the BSER but that could materially help the EGUs achieve their emission limits and thereby provide compliance flexibility. Examples include, among numerous other approaches, investment in demand-side EE, co-firing with natural gas (for coal-fired steam EGUs), and investment in new generating units using low- or zero-carbon generating technologies other than those that are part of building block 3.
b.
As described in the proposal, to determine the BSER, the EPA began by considering the characteristics of CO
Similarly, in 1996, the EPA finalized section 111(b) standards and 111(d) emission guidelines to ensure that certain municipal solid waste (MSW) landfills controlled landfill gases to the level achievable through application of the BSER.
For this rule, we discuss at length in the proposed rule and in section II above the unique characteristics of CO
We also discuss at length in the proposal and in section II above the unique characteristics of the utility power sector. Topics of that discussion include the physical properties of electricity and the integrated nature of the electricity system. Here, we reiterate and emphasize that the utility power sector is unique in the extent to which it must balance supply and demand on a real-time basis, with limited electricity storage capacity to act as a buffer. In turn, the need for real-time synchronization across each interconnection has led to a uniquely high degree of coordination and interdependence in both planning and real-time system operation among the owners and operators of the facilities comprised within each of the three large electrical interconnections covering the contiguous 48 states. Given these unique characteristics, it is not surprising that the North American power system has been characterized as a “complex machine.”
The EPA also reviewed broad trends within the utility power sector.
The EPA examined state and company programs intended at least in part to reduce CO
We also examined federal legislative and regulatory programs, as well as state programs currently in operation, that address pollutants other than CO
In this rule, when evaluating the types and amounts of measures that the source category can take to reduce CO
The factors just discussed that support consideration of emission reduction measures at the source-category level likewise strongly support consideration of mechanisms such as emissions trading approaches, especially since, as discussed in section VIII, the states will have every opportunity to design their section 111(d) plans to allow the affected EGUs in their respective jurisdictions to employ emissions trading approaches to achieve the standards of performance established in those plans. In short, as discussed in more detail in section V.A.2.f. below, it is entirely feasible for states to establish standards of performance that incorporate emissions trading, and it is reasonable to expect that states will do so. These approaches lower overall costs, add flexibility, and make it easier for individual sources to address pollution control objectives. To the extent that the purchase of an emissions credit or allowance represents the purchase of surplus emission reductions by an emitting source, emissions trading represents, in effect, the investment in pollution control by the purchasing source, notwithstanding that the control activity may be occurring at another source. As noted above, the utility power sector has a long history of using the “complex machine” to address objectives and constraints of various kinds. When afforded the opportunity to address environmental objectives on a multi-unit basis, the industry has done so. Congress and the EPA have selected emissions trading approaches when addressing regional pollution from the utility power sector contributing to problems such as acid precipitation and interstate transport of ozone and particulate matter. Similarly, states have selected market-based approaches for their own programs to address regional and global pollutants. The industry has readily adapted to that form of regulation, taking advantage of the flexibility and incorporating those programs into the planning and operation of the “machine.” Further reinforcing our conclusion that reliance on trading is appropriate is the extensive interest in using such mechanisms that states and utilities demonstrated through their formal comments and in discussions during the outreach process. The role of emissions trading is discussed further in section V.A.2.f. below.
This entire review has made clear that there are numerous measures that, alone or in various combinations, merit analysis for inclusion in the BSER. The review has also made clear that the unique characteristics of CO
The measures are discussed more fully below, but it should be noted here that because of the integrated nature of the utility power sector—in which individual EGUs' operations intrinsically depend on the operations of other generators—coupled with the sector's high degree of planning and reliability safeguards, the measures in the second and third categories (which involve generation shifts to lower- and zero-emitting sources) may occur through several different actions from the perspective of an individual source, all of which are equivalent from the perspective of the source category as a whole. First, a higher-emitting fossil unit may invest in cleaner generation without reducing its own generation, which, in the presence of requirements for the source category as a whole to reduce CO
Each state has significant flexibility in several respects. For example, as mentioned, a state may impose standards of performance on its steam EGU sources and on its combustion turbine sources that simply reflect the respective CO
In instances where a state establishes standards of performance that incorporate emissions trading, the tradable credits or allowances can serve as a medium through which affected EGUs can invest in any emission reduction measure.
d.
(1)
As described in the proposal, the measures that the affected EGUs could implement to improve their CO
These heat rate improvement measures include best practices such as improved staff training, boiler chemical cleaning, cleaning air preheater coils, and use of various kinds of software, as well as equipment upgrades such as turbine overhauls. These are measures that the owner/operator of an affected coal-fired steam EGU may take that would have the effect of reducing the amount of CO
These heat rate improvements are a low-cost option that fit the criteria for the BSER, except that they lead to only small emission reductions for the source category.
Specifically, as described in the proposal, the EPA also considered co-firing (including 100 percent conversion) with natural gas, a measure that presented itself in part because of the recent increase in availability and reduction in price of natural gas, and the industry's consequent increase in reliance on natural gas.
However, these co-firing and CCS measures are more expensive than other available measures for existing sources. This is because the integrated nature of the electricity system affords significantly lower cost options, ones that fossil fuel-fired power plants
The less expensive options include shifting generation to existing NGCC units—an option that has become particularly attractive in light of the increased availability and lower prices of natural gas—as well as shifting generation to new RE generating units. A comparison of the costs of converting an existing coal-fired boiler to burn 100 percent natural gas compared to the cost of shifting generation to an existing NGCC unit illustrates this point. Because an NGCC unit burns natural gas significantly more efficiently than an affected steam EGU does, the cost of shifting generation from the steam EGU to an existing NGCC unit is significantly cheaper in most cases than more aggressive emission rate reduction measures at the steam EGU. As a result, as a practical matter, were the EPA to include co-firing and CCS in the BSER and promulgate performance standards accordingly, few EGUs would likely comply with their emission standards through co-firing and CCS; rather, the EGUs would rely on the lower cost options of substituting lower- or zero-emitting generation or, as a related matter, reducing generation.
The EPA also considered heat rate improvement opportunities at oil- and gas-fired steam EGUs and NGCC units and found that the available emission reductions would likely be more expensive or too small to merit consideration as a material component of the BSER.
Thus, in reviewing the entire range of control options, it became clear that controlling CO
Although the presence of lower-cost options that achieve the emission reduction goals means that the EPA is not identifying either natural gas co-firing or CCS at coal-fired steam EGUs, or heat rate improvements at other types of EGUs, as part of the BSER, those controls remain measures that some affected EGUs may be expected to implement and that as a result, will provide reductions that those affected EGUs may rely on to achieve their emission limits or may sell, through emissions trading, to other affected EGUs to achieve emission limits (to the extent permitted under the relevant section 111(d) plans). Another example of a non-BSER measure that an affected EGU in certain circumstances could choose to implement is the conversion of waste heat from electricity generation into useful thermal energy. The EPA further discusses the potential use of these non-BSER measures for compliance flexibility below.
The EPA's quantification of the CO
(2)
To determine the BSER that meets the expectations and requirements of the CAA, including the achievement of meaningful reductions of CO
It bears reiterating that the extent to which the operations of individual affected EGUs are integrated with one another and with the overall electricity system is a highly salient and unique attribute of this source category. Because of this integration, the individual sources in the source category operate through a network that physically connects them to each other and to their customers, an interconnectedness that is essential to their operation under the status quo and by all indications is projected to be augmented further on a continual basis in the future to address fundamental objectives of reliability assurance and cost reduction. This physical interconnectedness exists to serve a set of interlocking regimes that, to a substantial extent, determine, if not dictate, any given EGU's operations on a nearly moment-to-moment basis. In analyzing BSER from the perspective of the overall source category, because the affected EGUs are connected to each other operationally, a combination of dispatching and investment in lower- and zero-emitting generation allows the replacement of higher-emitting generation with lower-emitting and zero-emitting generation (measures in building blocks 2 and 3), and thereby reduces emissions while continuing to serve load.
As noted above, substitution of higher-emitting generation for lower- or zero-emitting generation may include reduced generation, depending on the specific action taken by the individual EGU. Likewise, when incorporated into standards of performance, emissions trading mechanisms may be readily used for implementing these building blocks. We discuss these aspects below in describing the actions that individual sources may take to implement the building blocks.
(a)
In the proposal, the EPA observed that substantial CO
As described in section V.D. below, analysis reflecting consideration of the many comments we received on the EPA's proposal with respect to this issue supports the inclusion of generation shifting from higher-emitting to lower-emitting EGUs as a component of the BSER. Shifting of generation
The EPA's analysis continues to show that the magnitude of emission reductions included in the proposed rule from generation shifting is achievable. In response to our request for comment on the proposed target utilization rates, some commenters stated that summer capacity ratings are a more appropriate basis upon which to compute a target utilization than nameplate capacity ratings used at proposal. We agree, and accordingly, using the same data on historical generation as at proposal, we have reanalyzed feasible NGCC utilization levels expressed in terms of summer capacity ratings and have found that a 75 target utilization rate based on summer capacity ratings is feasible.
The EPA is finalizing a determination that generation shift from higher-emitting affected EGUs to lower-emitting affected EGUs is a component of the BSER (building block 2). Our quantification of the associated emission reductions is discussed in section V.D. of this preamble and in the GHG Mitigation Measures TSD for the CPP Final Rule.
(b)
Reducing generation from fossil fuel-fired EGUs and replacing it with generation from lower- or zero-emitting EGUs is another method for reducing CO
(i)
The EPA's survey of trends and actions already being taken in the utility power sector indicated that RE generating capacity and generation have grown rapidly in recent years, in part because of the environmental benefits of shifting away from fossil fuel-fired generation and in part because of improved economics of RE generation relative to fossil fuel-fired generation. It is clear that increasing the amount of new RE generating capacity and allowing the increased RE generation to replace generation from fossil fuel-fired EGUs can reduce CO
The EPA is finalizing the determination that substitution of RE generation from new RE generating capacity is a component of the BSER but, with the benefit of comments responding to the EPA's proposals on regionalization and techno-economic analytic approaches, the EPA has adjusted the approach for determining the quantities of RE generation. As part of the adjustment in approach, we have also refocused the quantification solely on generation from new RE generating capacity rather than total (new and existing) RE generating capacity as in the proposal. Our quantification of the RE generation component of the BSER is discussed in section V.E. of the preamble and in the GHG Mitigation Measures TSD for the CPP Final Rule.
(ii)
In the June 2014 proposal, the EPA also identified the replacement of generation from fossil fuel-fired EGUs with generation from nuclear units as a potential approach for reducing CO
Like generation from new RE generating capacity, generation from new nuclear generating capacity can clearly replace fossil fuel-fired generation and thereby reduce CO
The EPA is likewise not finalizing the proposal to include a component representing preserved existing nuclear generation in the BSER. On further consideration, we believe it is inappropriate to base the BSER on elements that will not reduce CO
(iii)
New NGCC units—that is, units that had not commenced construction as of January 8, 2014, the date of publication of the proposed CO
The EPA did not include reduced generation from affected EGUs achieved through construction and operation of new NGCC capacity in the proposed BSER because we expected that the CO
Unlike emission reductions achieved through the use of any of the building blocks, emission reductions achieved through the use of new NGCC capacity require the construction of additional CO
Commenters also raised a concern with the interrelation of section 111(b) and section 111(d). New NGCC capacity is distinguished from the other non-BSER measures discussed above by the fact that its CO
(c)
The final category of approaches for reducing generation and CO
Commenters expressed a wide range of views on the proposed reliance on demand-side EE in the BSER. Some commenters strongly supported the proposal, with suggestions for improvements, while some commenters strongly opposed the proposal and took the position that it exceeded the EPA's legal authority. We do not address the merits of these comments here because, for the reasons discussed in section V.B.3.c.(8) below, we are not finalizing the proposal to include avoided generation achieved through demand-side EE as a component of the BSER. However, we note that most commenters also supported the use of demand-side EE for compliance whether or not it is used in determining the BSER, and we are allowing demand-side EE to be used for that purpose. (We also emphasize that the emission limitations reflective of the BSER are achievable even if aggregate generation is not reduced through demand-side EE.)
(3)
While the discussion above summarizes how and why the components of the BSER were determined in terms of qualitative characteristics, it still leaves a wide range of potential stringencies for the BSER. As explained in sections V.C., V.D., and V.E. below, discussing building blocks 1, 2, and 3 respectively, the EPA has determined a reasonable level of stringency for each of the building blocks rather than the maximum possible level of stringency. We have taken this approach in part to ensure that there is “headroom” within the BSER measures that provides greater assurance of the achievability of the BSER for the source category and for individual sources. We believe this approach is permissible under the CAA. Another aspect of our methodology for computing the CO
Further, the sets of measures in each of these individual building blocks, in the stringency assigned in this rule, meet the criteria for the BSER. That is, they each achieve the appropriate level of reductions, are of reasonable cost, do not impose energy penalties on the
For example, all of the measures in building blocks 2 and 3 have been implemented for decades, initially for reasons unrelated to pollution control, then in recent years in order to control non-GHG air pollutants, and more recently, for purposes of CO
It should also be noted that building blocks 2 and 3 also meet the criteria for the BSER in combination with one another and with building block 1, as described below.
e.
(1)
An affected EGU may take steps to improve its CO
(2)
Viewing the BSER from the perspective of an individual EGU, there are several ways that affected EGUs can access the measures in building blocks 2 and 3, thanks to the integrated nature of the electricity system, coupled with the system's high degree of planning and reliability mechanisms. The affected EGUs can: (a) Invest in lower- or zero-emitting generation, which will lead to reductions in higher-emitting generation at other units in the integrated system; (b) reduce their generation, which in the presence of emission reduction requirements applicable to the source category as a whole will have the effect of increasing demand for, and thereby incentivize investment in, the measures in the building blocks elsewhere in the integrated system; or (c) both invest in the measures in the building blocks and reduce their own generation, effectively replacing their generation with cleaner generation. The availability of these options is further enhanced where the individual EGU is operating under a standard of performance that incorporates emissions trading.
(a)
An affected EGU may take the following actions to invest in the measures in building blocks 2 and 3. For building block 2, the owner/operator of a steam EGU may increase generation at an existing NGCC unit it already owns, or one that it purchases or invests in. In addition, the owner/operator may, through a bilateral transaction with an existing NGCC unit, pay the unit to increase generation, and acquire the CO
Similarly, for building block 3, an owner/operator of an affected EGU may build, or purchase an ownership interest in, new RE generating capacity and acquire the CO
In case of an investment in either building block 2 or building block 3 by a unit subject to a rate-based form of CO
When combined with reduced generation, either at the affected EGU or elsewhere in the interconnected system, the types of actions listed above would be fully equivalent to building blocks 2 and 3 when viewed from the perspective of the overall source category. Thus, a source could achieve a standard of performance identical to the applicable CO
The EPA anticipates that in instances where section 111(d) plans provide for the use of instruments such as ERCs as a mechanism to facilitate use of these measures, organized markets will develop so that owner/operators of affected EGUs that have invested in measures eligible for the issuance of ERCs will be able to sell those credits and other affected EGUs will be able to purchase them. Such markets have developed for other instruments used for emissions trading purposes. For example, liquid markets for SO
If states choose to allow through their section 111(d) plans mechanisms or standards of performance involving instruments such as ERCs, the EPA believes that there would be an ample supply of such credits, for several reasons. First, as discussed in sections V.D. and V.E., the EPA has established the stringencies for building blocks 2 and 3 at levels that are reasonable and not at the maximum achievable levels, providing headroom for investment in the measures in these building blocks beyond the amounts reflected in the CO
It should also be noted that although in a state that sets emission limits in a rate-based form the measures in building blocks 2 and 3 can be taken into account directly in computations to determine whether an individual affected EGU has achieved its emission limit, in a state that sets emission limits in a mass-based form these measures are not taken into account directly in computations to determine whether an individual affected EGU has achieved its emission limit. However, by reducing generation and therefore CO
(b)
In addition, the owner/operator of an affected EGU may help itself meet its emission limit by reducing its generation. If the owner/operator reduces generation and therefore the amount of its CO
An owner/operator may take actions to ensure that it reduces its generation. For example, it may accept a permit restriction on the amount of hours that it generates. In addition or alternatively, it may represent the cost of additional emission credits or allowances that would be required due to incremental generation as an additional variable cost that increases the total variable cost considered when dispatch decisions are made for the unit.
Because of the integrated nature of the electricity system, combined with the system's high degree of planning and reliability safeguards, as well as the long planning horizon afforded by this rule, individual affected EGUs can implement the building blocks by reducing generation to achieve their emission performance standards.
(c)
As described above, viewed from the perspective of the source category as a whole, it is reasonable for our analysis of the BSER to include an element of source-category-wide multi-unit compliance which could be implemented via a state-set standard of performance incorporating emissions trading, under which EGUs could engage in trading of rate-based emission credits or mass-based emission allowances. By the same token, viewed from the perspective of an individual EGU, consideration of the ready availability to states of the opportunity to establish standards of performance that incorporate emissions trading is integral to our analysis. Accordingly, our assessment of the actions available to individual EGUs for achieving standards of performance reflecting the BSER includes the purchase of rate-based emission credits or mass-based emission allowances, because one of the things an affected EGU can do to achieve its emission limit is to buy a credit or an allowance from another affected EGU that has over-complied. The use of purchased credits or allowances would have to be authorized, of course, in the purchasing EGUs' states' section 111(d) plans and would have to meet conditions set out for such approaches in section VIII below. The role of emissions trading in the BSER analysis is discussed further in section V.A.2.f. below.
f.
In addition, several groups of states supported trading programs: Georgetown Climate Center (a group of state environmental agency leaders, energy agency leaders, and public utility commissioners from California, Colorado, Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Minnesota, New Hampshire, New York, Oregon, Rhode Island, Vermont, and Washington) (“We believe states should have maximum flexibility to determine what kinds of collaborations might work for them. These could include submission of joint plans, standardized approaches to trading renewable or energy efficiency credits. . . . We also encourage EPA to help facilitate such interstate agreements or multi-state collaborations by working with states to either identify or provide a platform or framework that states may elect to use for the tracking and trading of avoided generation or emissions credits due to interstate efficiency or renewable energy.” comment 23597, at 39-40); RGGI (including Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, Vermont) (“[E]very serious proposal to reduce carbon emissions from EGUs, from proposed US legislation to programs in place in California and Europe, has identified allowance trading as the best approach.” Comment 22395 at 7-8); Western States Center for New Energy Economy (including Arizona, California, Colorado, Idaho, Montana, Nevada, Oregon, South Dakota, Utah, Washington) (“Some degree of RE and EE credit trading among states may support compliance, even in the absence of a comprehensive regional plan. Therefore, EPA should support approaches which allow states flexibility to allocate credit for these zero-carbon resources, along with approaches which allow states to reach agreements on the allocation of carbon liabilities. This includes ensuring that existing tracking mechanisms for renewable energy in the West, such as the Western Renewable Energy Generation Information System (WREGIS), are compatible with the final proposal.” Comment 21787 at 5); Midcontinent States Environmental and Energy Regulators (including Arkansas, Illinois, Michigan, Minnesota Missouri, Wisconsin) (EPA should also provide states with optional . . . systems (or system) for tracking emissions, allowances, reduction credits, and/or generation attributes that states may choose to use in their 111(d) plans,” comment 22535 at 3).
In addition, trading programs were supported by, among others, a group of Attorneys General from 11 states and the District of Columbia. Comment 25433 (Attorneys General from New York, California, Connecticut, Maine, Maryland, Massachusetts, New Mexico, Oregon, Rhode Island, Vermont, Washington, District of Columbia, and New York City Corporation Counsel).
Numerous industry commenters also supported trading, including Alliant Energy Corporate Services, Inc. (comment 22934), Calpine (comment 23167), DTE Energy (comment 24061), Exelon (comment 23428 and 23155), Michigan Municipal Electric Association (MMEA) (comment 23297), National Climate Coalition (comment 22910), Pacific Gas and Electric Company (comment 23198), Western Power Trading Forum (WPTF) (comment 22860). Environmental advocates also supported trading, including Clean Air Task Force (comment 22612), Environmental Defense Fund (comment 23140), Institute for Policy Integrity, New York University School of Law (comment 23418).
The states' and EGUs' interest in emissions trading is rooted in the well-recognized benefits that trading provides. The experience of multiple trading programs over many years has shown that some units can achieve emission reductions at lower cost than others, and a system that allows for those lower-cost reductions to be maximized is more cost-effective overall to the industry and to society. Trading provides an affected EGU other options besides direct implementation of emission reduction measures in its own facility or an affiliated facility when lower-cost emission reduction opportunities exist elsewhere. Specifically, the affected EGU can cross-invest, that is, invest in actions at facilities owned by others, in exchange for rate-based emission credits or mass-based emission allowances. Through cross-investment, trading allows each affected EGU to access the control measures that other affected EGUs decide to implement, which in this case include all the building blocks as well as other measures.
Accordingly, our analysis of the measures under consideration in our BSER determination reflected the well-
Whether viewed from the perspective of an individual EGU or the source category as a whole, emissions trading is thus an integral part of our BSER analysis. Again, we concluded that this is reasonable given the global nature of the pollutant, the transactional and interconnected nature of this industry, and the long history and numerous examples demonstrating that, in this sector, trading is integral to how regulators have established, and sources have complied with, environmental and similar obligations (such as RE standards) when it was appropriate to do so given the program objective. The reasonableness is further demonstrated by the numerous comments (some of which are noted above) from industry, states, and other stakeholders in this rulemaking that supported allowing states to adopt trading programs to comply with section 111(d) and encouraged EPA to facilitate trading across state lines through the use of trading-ready state plans. The EPA's reliance on trading in its BSER determination does not mean, however, that states are required to establish trading programs (just as states are not required to implement the building blocks that comprise BSER). Nor does it mean that trading is the only transactional approach that we could have considered in setting the BSER or that states could use to effectuate the building blocks were they to decide that they did not want to take on the responsibility of running a trading program. Rather, it is simply a recognition of the nature of this industry and the long history of trading as an important regulatory tool in establishing regulatory regimes for this industry and its reasonable availability to states in establishing standards of performance.
As an initial matter, trading is permissible for these emission guidelines because CO
Further, as discussed elsewhere in the preamble, the utility power sector—and the affected EGUs and other generation assets that it encompasses—has a long history of working on a coordinated basis to meet operating and environmental objectives, necessitated and facilitated by the unique interconnectedness and interdependence of the sector. That history includes joint dispatch for economic and reliability purposes, both within large utility systems and in multi-utility power pools that have evolved into RTOs; joint power plant ownership arrangements; and long-term and short-term bilateral power purchase arrangements. More recently, the sector's history also includes emissions trading programs designed by Congress, the EPA, and the states to address regional environmental problems and, most recently, climate change. Examples of such programs are noted below.
Essentially, trading does nothing more than commoditize compliance, with the following two important results emerging from that: It reduces the overall costs of controls and spreads those costs among the entire category of regulated entities while providing a greater range of options for sources that may not want to make on-site investments for controlling their emissions and may prefer to make the same investment, via the purchase of the tradable compliance instrument, at another generating source. Building blocks 2 and 3 entail affected EGUs investing in increased generation from existing NGCC units and RE. The affected EGUs could do so in any number of ways, including acquiring ownership interests in existing NGCC or RE facilities or entering into bilateral transactions with the owners of existing NGCC facilities or RE sources. As discussed elsewhere, it is reasonable to expect that these actions can develop into discrete, tradable commodities (
By the same token, the opportunity to trade incentivizes affected EGUs to over-comply with building block 1. Thus, the opportunity to trade supports the EPA's assumptions about what an average affected EGU can achieve with regards to heat rate improvement even if each and every affected EGU cannot achieve that level of improvement. In addition, trading incentivizes affected EGUs to consider low-cost, non-BSER methods to reduce emissions as well, and, as discussed below, there are numerous non-BSER methods, ranging from implementation of demand-side EE programs to natural gas co-firing.
Trading has become an important mechanism for achieving environmental goals in the electricity sector in part because trading allows environmental regulators to set an environmental goal while preserving the ability of the operators of the affected EGUs to decide the best way to meet it taking account of the full range of considerations that govern their overall operations. For example, commenters were concerned that because of building block 2, the emission guidelines would require state environmental regulators to make dispatch decisions for the electricity markets, a role that state environmental regulators do not currently play. Although building block 2 entails substituting existing NGCC generation for steam generation, implementing the emission limits that are based in part on building block 2 through a trading program provides the individual affected EGUs with a great deal of control over their own generation while the industry as a whole achieves the environmental goals. For example, individual steam generators have the option of maintaining their generation as long as they acquire additional ERCs. Moreover, trading provides a way for states to set standards of performance that realize the required emissions reduction without requiring any form of “environmental dispatch” because, as many existing trading programs have shown, monetization of the environmental constraint is consistent with a least-cost dispatch system. Trading also supports the EPA's approach to the “remaining useful life” provision in section 111(d)(1) because with trading, an affected EGU with a
The EPA's job in issuing these emission guidelines is to determine the BSER that has been adequately demonstrated and to set emission limitations that are achievable through the application of the BSER and implementable through standards of performance established by the states. The three building blocks are the EPA's determination of what technology is adequately demonstrated. We also consider trading an integral part of the BSER analysis because, in addition to being available to states for incorporation in the standards of performance they set for affected EGUs, trading has been adequately demonstrated for this industry in circumstances where systemic rather than unit-level reductions are central. Congress, the EPA, and state regulators have established successful environmental programs for this industry that allow trading of environmental (or similar) attributes, and trading has been widely used by the industry to comply with these programs. Examples include the CAA Title IV Acid Rain Program, the NO
Based on this history, it is reasonable for the EPA to determine that states can establish standards of performance that incorporate trading and, as a result, for the purpose of making a BSER determination here to evaluate prospective emission control measures in light of the availability of trading. Trading is a regulatory mechanism that works well for this industry. The environmental attributes in the preceding programs (representing emissions of air pollutants) are identical to or similar in nature to the environmental attribute here (CO
Given the benefits of trading and the background of multi-unit coordination grounded in the nature of the utility power sector, it is natural for sources and states to look for opportunities to apply similar coordination to a regional problem such as reduction of CO
g.
h.
i.
As discussed below, each affected EGU can achieve the performance rate by implementing the BSER, specifically, by taking a range of actions—some of which depend on features of the section 111(d) plan chosen by the state, such as the choice of rate-based or mass-based standards of performance and the choice of whether and how to permit emissions trading—including investment in the building blocks, replaced or reduced generation, and purchase of emission credits or allowances. Further, in the case of a rate-based state plan, several other compliance options not included in the BSER for this rule are also available to all affected EGUs, including investment in demand-side EE measures. Such compliance options may also indirectly help affected EGUs achieve compliance under a mass-based plan.
Our approach of subcategorizing between steam EGUs and combustion turbines is reasonable because building blocks 1 and 2 apply only to steam EGUs. Moreover, our approach of not further subcategorizing as between different types of steam EGUs or combustion turbines reflects the reasonable policy that affected EGUs with higher emission rates should reduce their emissions by a greater percentage than affected EGUs with lower emission rates and can do so at a reasonable cost using the approaches we have identified as the BSER as well as other available measures.
Of course, a state retains great flexibility in assigning standards of performance to its affected EGUs and can impose different emission reduction obligations on its sources, as long as the overall level of emission limitation is at least as stringent as the emission guidelines, as discussed below.
For the BSER determined in this final rule, based on consideration of comments responding to a broad array of topics considered in the proposal, the EPA has adopted certain modifications to the proposed BSER. In this subsection we describe the most important modifications, including some that relate to individual building blocks and some that are more general. Additional modifications that relate to individual building blocks are discussed in the respective sections for those building blocks below (sections V.C. through V.E.).
We note that taken together, the modifications yield emission reductions requirements that commence more gradually than the proposed goals but are projected to produce greater overall annual emission reductions by 2030.
a.
Two of these points merit mention here. First, the EPA is clarifying in this rule that the interpretation of “system of emission reduction” does not include emission reduction measures that the states have authority to mandate without the affected EGUs being able to implement the measures themselves (
Second, the EPA has adopted a combined interpretation of sections 111(a)(1) and 111(d) that, compared to the proposal, better reflects the historical interpretations of section 111(a)(1), which have generally supported emissions standards that are nationally uniform for sources incorporating a given technology, and gives less weight to the state-focused character of section 111(d), which calls for emissions standards to be implemented through the development of individual state plans. The proposed state goals were heavily (although not entirely) dependent on the emission reduction opportunities available to the EGUs in each individual state, and because the relative magnitudes of these opportunities varied by state, states with similar EGU fleet compositions could have faced state goals of different stringencies, potentially making it difficult for multiple states to set the same standards of performance for affected EGUs using the same technologies (assuming the states were interested in setting standards of performance for their various affected EGUs in such a manner). Some commenters viewed this potential result as inconsistent with section 111(a)(1), inequitable, or both. In response, we took further comment on these potential disparities in the October 30, 2014 NODA. In this final rule, we are obviating those concerns by assessing the emission reduction opportunities at an appropriate regional scale, consistent with alternatives on which we sought comment, and using this regional information to reformulate the proposed emissions standards as nationally
b.
In the June 2014 proposal, RE generation was also quantified as generation from total—that is, existing and new—RE generating capacity, a formulation that was consistent with the formulation of most RPS, which are typically framed in terms of total rather than incremental generation. In response to the EPA's request for comment on this approach, commenters observed that the approach was inconsistent with the approach taken for other building blocks, and that generation from RE generating capacity that already existed as of 2012 should not be treated as reducing emissions of affected EGUs from 2012 levels. As just noted, we are not using the RPS-based methodology in the final rule, and we agree with comments that quantification of RE generation on an incremental basis is both more consistent with the treatment of other building blocks and more consistent with the general principle that the BSER should comprise incremental measures that will reduce emissions below existing levels, not measures that are already in place, even if those in-place measures help current emission levels be lower than would be the case without the measures. The final rule therefore defines the RE component of the BSER in terms of incremental rather than total RE generation.
c.
The EPA received numerous comments on the proposed BSER components related to nuclear power. With respect to generation from under-construction nuclear units, some commenters expressed strong opposition to the inclusion of this generation in the BSER and the setting of state goals, stating that inclusion would result in very stringent state goals for the states where the units are being built and that the inclusion of the generation in the goals is premature because the units' actual completion dates could be delayed. Commenters also stated that inclusion of the under-construction nuclear generation in the BSER would be inequitable because states where the same heavy investment in zero-CO
With respect to generation from existing nuclear units, some commenters stated that our method of accounting for potential unit shutdowns was flawed, observing that even if the prediction of a 5.8 percent nationwide loss of nuclear generation were accurate, the actual shutdowns would occur in a handful of states, resulting in much larger losses of generation in those particular states.
Upon consideration of comments and the accompanying data, the EPA has determined that the BSER should not include either of the components related to nuclear generation from the proposal. With respect to nuclear units under construction, although we believe that other refinements to this final rule would address commenters' concerns that goals for the particular states where the units are located would be overly stringent either in absolute terms or relative to other states, we also acknowledge that, in comparison to RE generating technology, investments in new nuclear units tend to be individually much larger and to require longer lead times. Also, important recent trends evidenced in RE development, such as rapidly growing investment and rapidly decreasing costs, are not as clearly evidenced in nuclear generation. We view these factors as distinguishing the under-construction nuclear units from RE generating capacity, indicating that the new nuclear capacity is likely of higher cost and therefore less appropriate for inclusion in the BSER. Excluding the under-construction nuclear units from the BSER, but allowing emission reductions attributable to generation from the units to be used for compliance as discussed below and in section VIII, will recognize the CO
With respect to existing nuclear units, although again we believe that other refinements in the final rule would address the concern about disparate impacts on particular states, we acknowledge that we lack information on shutdown risk that would enable us to improve the estimated 5.8 percent factor for nuclear capacity at risk of
Generation from under-construction or other new nuclear units and capacity uprates at existing nuclear units would still be able to help sources meet emission rate-based standards of performance through the creation and use of credits, as noted in section V.A.6.b. and section VIII.K.1.a.(8), and would help sources meet mass-based standards of performance through reduced utilization of fossil generating capacity leading to reduced CO
d.
As explained in section V.B.3.c.(8) below, our traditional interpretation and implementation of CAA section 111 has allowed regulated entities to produce as much of a particular good as they desire provided that they do so through an appropriately clean (or low-emitting) process. While building blocks 1, 2, and 3 fall squarely within this paradigm, the proposed building block 4 does not. In view of this, since the BSER must serve as the foundation of the emission guidelines, the EPA has not included demand-side EE as part of the final BSER determination.
It should be noted that commenters also took the position that the EPA should allow demand-side EE as a means of compliance with the requirements of this rule, and, as discussed in section V.A.6.b. and section VIII below, we agree.
e.
For the final rule, with the benefit of comments received in response to these proposals and alternatives, we have adopted a consistent regionalized approach to quantification of emission reductions achievable through all the building blocks. Under this approach, each of the building blocks is quantified and applied at the regional level, resulting in the computation for each region of a performance rate for steam EGUs and a performance rate for NGCC units. For each of the technology subcategories, we identify the most conservative—that is, the least stringent —of the three regional performance rates. We then apply these least stringent subcategory-specific performance rates to the baseline data for the EGU fleet in each state to establish state goals of consistent stringency across the country. (Note that the actual state goals vary among states to reflect the differences in generation mix among states in the baseline year.) Further description of the steps in this overall process is contained in the preamble sections addressing the individual building blocks (sections V.C., V.D., and V.E.), CO
Compared to the more state-focused quantification approach selected in the proposal, and as recognized in the NODA, a regionalized approach better reflects the interconnected system within which interdependent affected EGUs actually carry out planning and operations in order to meet electricity demand. We have already discussed the relevance of the interconnected system and the interdependent operations of EGUs as factors supporting consideration of building blocks 2 and 3 as elements of the BSER for this pollutant and this industry, and these same factors support quantifying the emission reductions achievable through building blocks 2 and 3 on a regionalized basis. Because it better reflects how the industry works, a regionalized approach also better represents the full scope of emission reduction opportunities available to individual affected EGUs through the normal transactional processes of the industry, which do not stop at state borders but rather extend throughout these interconnected regions. With respect to building block 1, which comprises types of emission reduction measures that in other rulemakings under CAA section 111 would typically be evaluated on a nationwide basis, for this rule, as discussed in section V.C. below, we are quantifying the emission reductions achievable through building
Characterizing and quantifying the measures included in the BSER on a regional basis rather than a state-limited basis is also appropriate because states can establish standards of performance that incorporate emissions trading, including trading between and among EGUs operating in different states, and thus provide EGUs the opportunity to trade. Emissions trading provides at least one mechanism by which owners of affected EGUs can access any of the building blocks at other locations. With emissions trading, an affected EGU whose access to heat rate improvement opportunities, incremental generation from existing NGCC units, or generation from new RE generating capacity is relatively favorable can overcomply with its own standard of performance and sell rate-based emission credits or mass-based emission allowances to other affected EGUs. Purchase of the credits or allowances by the other EGUs represents cross-investment in the emission reduction opportunities, and such cross-investment can be carried out on as wide a geographic scale as trading rules allow.
The regions we have determined to be appropriate for the regionalized approach in the final rule are the Eastern, Western, and Texas Interconnections.
Second, we considered whether the interconnection subregions for which various planning and operational functions are carried out by separate institutional actors would represent more appropriate regions than the entire interconnnections, and concluded that they would not. Interconnection planning and management follows the NERC functional model, which defines subregional areas and regional entities within each interconnection for the purposes of balancing generation with load and ensuring that reliability is maintained. While a variety of organizations plan and operate these subregions, those activities always occur in the context of the interconnections, and the subregions cannot be operated autonomously. The need to maintain common frequency and stable voltage levels throughout the interconnections requires constantly changing flows of electricity between the planning and operating subregions within each interconnection.
Because each interconnection is a freely flowing AC grid, any power generated or consumed flows through the entire interconnection in real time; as a result of this highly interconnected nature of the power system, the management of generation and load on the grid must be carefully maintained. This management is carried out principally by subregional entities responsible for the operation of the grid, but this operation must be coordinated in real time to ensure the reliability of the system. Regional operators must coordinate the dispatch of power, not only in their own areas, but also with the other subregions within the interconnection. Although this coordination has always been important, grid planning and management has evolved to be increasingly interconnection-wide, through the development of larger regional entities, such as RTO/ISOs, or large-utility dispatch across multiple balancing areas. As a result, the fact that much of the necessary coordination for the interconnections is performed regionally on a partially decentralized basis (at least in the case of the Eastern and Western Interconnections) or occurs through the operation of automated equipment and the physics of the grid does not render the subregions more relevant than the interconnections as the ultimate regions within which electricity supply and demand must balance.
Moreover, some planning and standard setting activities are undertaken explicitly at the interconnection level. For example, interconnections also have interconnection reliability operating limits (IROLs).
Congress recognized the significance of the three interconnections in the American Recovery and Reinvestment Act of 2009 (Recovery Act) when it provided $80 million in funding for interconnection-based transmission planning.
In Order No. 1000, FERC also took a broader regional view of transmission planning.
In addition to Congressional, DOE, and FERC recognition of the importance of the three interconnections, NERC also considers them to be significant. NERC Organizational Standards “are based upon certain Reliability Principles that define the foundation of reliability for North American bulk electric systems.”
The importance that Congress, DOE, FERC, and NERC each place upon the interconnections for electric reliability and operational issues is another factor supporting our decision to set the interconnections as the regional boundaries for the establishment of BSER. The utilization of the three interconnections for both planning and reliability purposes is a clear indication of the importance that electricity system regulators, operators, and industry place upon the interconnections. Those responsible for the electricity system recognize the need to ensure that there is a free flow of electricity throughout each interconnection such that transmission planning and reliability analysis are occurring at the interconnection level. Further, this vigilance with respect to considering reliability from an interconnection-wide basis recognizes that each of the interconnections behaves as a single machine where “outages, generation, transmission changes, and problems in any one area in the synchronous network can affect the entire network.”
An additional factor weighing against the use of planning or operational subregions of the interconnections as the regions for our BSER analysis for this rule is that the borders of those subregions occasionally change as planning and management functions evolve or as owners of various portions of the grid change affiliations. This is not a merely theoretical consideration; numerous ISO/RTO and other regional boundaries have substantially changed in recent years. For example, in 2012, Duke Energy Ohio and Duke Energy Kentucky integrated into PJM.
Third, we considered whether transmission constraints, and the fact that the specific locations of generation resources and loads within each interconnection clearly matter to grid planning and operations, necessitate evaluation of the emission reductions available from the building blocks at scales smaller than the interconnections. We concluded that no reduction in scale was needed due to such constraints. The same industry trends that are reflected in the BSER—the changing efficiencies and mix of existing fossil EGUs and the development of RE throughout each interconnection—as well as the management of the interconnected grid as loads are reduced through EE, which is not reflected in the final BSER, are already driving power system development and are being managed through interconnection-wide planning, coordination and operations, and will continue to be managed in that manner in the future with or without this rule. While electricity supply and demand must be balanced in real time in a manner that observes all security constraints at that point in time, and key aspects of that management are carried out at a subregional scale, the emissions standards established in this rule can be met over longer timeframes through processes managed at larger geographic scales, just as they are today. We believe this rule will reinforce these developments and help provide a secure basis for moving forward. If a local transmission constraint requires that for reliability reasons a higher-emitting resource must operate during a certain period of time in preference to a lower-emitting resource that would otherwise be the more economic choice when all costs are considered, nothing in this rule prevents the higher-emitting source from being operated. If the same transmission constraint causes the same conditions to occur frequently, the extra cost associated with finding alternative ways to reduce emissions will provide an economic incentive for concerned parties to explore ways to relieve the transmission constraint. If relieving the constraint would be more costly than employing alternative measures to reduce emissions, the rule allows parties to pursue those alternative emission reduction measures. Accommodation of intermittent constraints and evaluation of alternatives for relieving or working around them have been routine operating and planning practices within the utility power sector for many years; the rule will not change these basic economic practices that occur today. The 2022-29 schedule for the rule's interim goals and the 2030 schedule for the rule's final goals allow time for planning and investment comparable to the sector's typical planning horizons.
Finally, the EPA also considered whether the smaller geographic scales on which affected EGUs may typically engage in energy and capacity transactions necessitate evaluating the emission reductions available from the building blocks at scales smaller than the interconnections, and again concluded that a smaller scale was not necessary or justified. We first note that electricity trading occurs today throughout the interconnection through RTO/ISO markets and active spot markets, often over large areas such as RTO/ISOs, or managed over large dispatch areas outside RTOs. These trades result in interconnection-wide changes in flow that are managed in real time. Moreover, the exchange of power is not limited to these areas. For example, RTOs regularly manage flows between RTOs, and EGUs near the boundaries of RTOs impact multiple subregions across the interconnections, so that any subregional boundaries that might be evaluated for potential relevance as trading region boundaries will change as conditions and EGU choices change, while interconnection boundaries will remain stable.
In addition, the final rule permits trading of rate-based emission credits or mass-based emission allowances. Emission allowances and other commodities associated with electricity generation activities, such as RECs, which, again, represent investments in pollution control measures, are already traded separately from the underlying electric energy and capacity. There is no reason that whatever geographic limits may exist for electricity and capacity transactions by an affected EGU should also limit the EGU's transactions for validly issued rate-based emission credits or mass-based emission allowances. In fact, as discussed below, the final rule not only allows national trading without regard to the interconnection boundaries, but also includes a number of options that readily facilitate states' and utilities' very extensive reliance on emissions trading. It is appropriate for the rule to take this approach, in part, because the non-local nature of the impacts of CO
f.
Specifically, the final rule establishes a performance rate of 1305 lbs. per net MWh for all affected steam EGUs nationwide and a performance rate of 771 lbs. per net MWh for all affected stationary combustion turbines nationwide. The computations of these performance rates and the determinations of state goals reflecting the performance rates are described in sections VI and VII of the preamble, respectively. As described above, in its proposed rule and NODA, the EPA solicited comment on a number of proposals to reflect the regional nature of the electricity system in the methodology for quantifying the emission limitations reflective of the BSER. At the same time, the EPA also consistently emphasized the need for strategies to ensure the achievability and flexibility of the established emission limitations and to increase opportunities for interstate and industry-wide coordination. This modification is consistent with a number of comments we received in response to those proposals. The commenters took the position that the proposed state goals varied too much among states and unavoidably implied, or would inevitably result in, states establishing inconsistent standards of performance for sources of the same technology type in their respective states, which in the commenters' view was not appropriate under section 111.
Having determined to adopt regional alternatives for computing the emission reductions achievable under each building block, the EPA has further determined to exercise discretion not to subcategorize based on the regions, and instead to apply a nationally uniform CO
Having determined that the performance rates computed on a regional basis merit consideration as nationally applicable performance rates, we are also determining that the objectives of achievability and flexibility would best be met by using the least stringent of the regional performance rates for the three interconnections for each technology subcategory as the basis for nationally uniform performance rates for that technology subcategory rather than by using the most stringent of the regional performance rates.
In addition, using the least stringent rate provides greater “headroom”—that is, emission reduction opportunities beyond those reflected in the performance rates—to affected EGUs in the interconnections that do not set the nationwide level. This greater “headroom” provides greater nationwide compliance flexibility and assurance that the standards set by the states based on the emission guidelines will be achievable at reasonable cost and without adverse impacts on reliability. This is because affected EGUs in the interconnections that do not set the nationwide level have more opportunities to directly invest in each of the building blocks in their respective regions, and affected EGUs in the interconnection that does set the nationwide level may in effect invest in the opportunities in the other interconnections through trading. At the same time, our approach still represents the degree of emission limitation achievable through use of an appropriately large and diverse set of emission reduction opportunities and can therefore reasonably be considered the “best” system of emission reduction for each technology subcategory.
Our approach in this rulemaking thus not only addresses the comments we received regarding potentially disparate impacts of the approach presented in the proposal, it is also generally consistent with the approach we have taken in other NSPS rulemakings, where standards of performance or emission guidelines have typically been established at uniform stringencies for all units in a given source subcategory, and where once the best system of emission reduction has been identified, stringencies are generally set based on what is reasonably achievable using that system.
Providing each state with a state-specific weighted average rate-based goal allows the state to determine how the emission reduction requirements should be allocated among the state's affected EGUs. We continue to believe that, as in the proposal, this is an important source of flexibility for states in developing their section 111(d) plans. Accordingly, in this final rule we are providing uniform CO
We note here that the weighted-average state goals reflect the application of the uniform CO
The computations of the uniform CO
g.
The EPA has considered these comments and in the final rule has established an interim compliance period of 2022-2029, providing two additional years for planning and investment before the start of compliance. We are persuaded by comments and by our own further analysis that this timeframe is appropriate and will, in combination with the glide path of emission reductions reflected in the final building blocks and the states' flexibility to define their own paths of emission reductions over the interim period (as discussed in section VIII), provide adequate time for necessary planning and investment activities. This will enable the final rule's requirements to be implemented in an orderly manner while reliability of electricity supplies is maintained. Further discussion is provided in the sections of the preamble addressing the individual building blocks (sections V.C., V.D., and V.E.) and on electricity system reliability (section VIII.G.2.).
The initial compliance date of 2022, coupled with the fact that the 2030 standard is phased in over the subsequent eight years, affords affected EGUs the benefit of having an extended planning period before they need to incur any significant obligations. Where needed, states may take the period through September 2018 to develop their final plans, and affected EGUs will be able to work with the states during that period to develop compliance approaches. States will also have the flexibility to select their own emissions trajectories in such a way that certain emission reduction measures could be implemented later in the interim period (again, provided that their affected EGUs still meet the interim performance rates or interim goal over the interim period as a whole). As a result, if the affected EGUs in those states need to incur any expenses before the adoption of the final state plans, those expenses need not be more than minimal. It is worth noting that an earlier state plan submission date provides regulated sources with more certainty and time to
These periods of time are consistent with current industry practice in changing generation or adding new generation. For example, in June 2015, Alabama Power Company announced plans to acquire 500 MW of RE generation over the next six years. This amount would make up between four and five percent of Alabama Power's generation mix.
h.
• Use of regional rates ranging from 2.1 percent to 4.3 percent (rather than 6 percent) as the average heat rate improvement opportunity achievable by steam units under building block 1.
• Use of 75 percent of summer capacity (rather than 70 percent of nameplate capacity) as the target capacity factor for existing NGCC units under building block 2.
• Use of updated information from the National Renewable Energy Laboratory (NREL) on RE costs and potential, and revision of the list of quantified RE technologies to exclude landfill gas under building block 3.
In this rule, the EPA is finalizing as the BSER a combination of building blocks 1, 2, and 3, with refinements as discussed below. The building blocks constitute the BSER from the perspective of the source category as a whole. Each building block can be implemented through standards of performance set by the states and includes a set of actions that individual sources can use to achieve the emission limitations reflecting the BSER. These actions and mechanisms, which include reduced generation and emissions trading approaches where the state-set standards of performance incorporate trading and which may be understood as part of the BSER, will be discussed below in section V.A.5. Each of the building blocks consists of measures that the source category and individual affected EGUs have already demonstrated the ability to implement. In quantifying the application of each building block, the EPA has identified reasonable levels of stringency rather than the maximum possible levels.
As discussed above, one of the modifications being made in this rule is the establishment of uniform performance rates by technology subcategory, which enhances the rule's achievability and flexibility and facilitates coordination among the states and across the industry. However, in the first instance, the emission reductions achievable through use of the building blocks are being evaluated on a regional basis that reflects the regional nature of the interconnected electricity system and the region-wide scope of opportunities available for affected EGUs to access emission reduction measures. The EPA recognizes that the emission reduction opportunities under these building blocks vary by region because of regional differences in the existing mix of types of fossil fuel-fired EGUs and the available opportunities to increase low- and zero-carbon generation. Consequently, in order to achieve uniform performance rates by technology subcategory, while respecting these regional differences in emission reduction opportunities, we have determined that it is reasonable not to establish the stringency of the BSER separately by region based on the maximum emission reduction that would be achievable in that region, but instead to establish uniform stringency across all regions at a level that is achievable at reasonable cost in any region. Thus, for each technology subcategory, the BSER is the combination of the elements described above at the combined stringency that is reasonably achievable in the region where the CO
This approach is consistent with the EPA's efforts to enhance the achievability and flexibility of the rule and to promote interstate and industry coordination and reflects the regional strategies emphasized in the proposal and the NODA. It is also consistent with the approach we have taken in other NSPS rulemakings, where the degree of emission limitation achievable through
As discussed in section XI of the preamble and the Regulatory Impact Analysis, application of the BSER determined as summarized above is projected to result in substantial and meaningful reductions of CO
Briefly, the elements of the BSER are:
a.
The EPA has analyzed the technical feasibility, costs, and magnitude of CO
Consideration of other BSER factors also favors a conclusion that building block 1 is a component of the BSER. For example, with respect to non-air health and environmental impacts, heat rate improvements cause fuel to be used more efficiently, reducing the volumes of, and therefore the adverse impacts associated with, disposal of coal combustion solid waste products. By definition, heat rate improvements do not cause increases in net energy usage. Although we are justifying building block 1 as part of the BSER without reference to technological innovation, we also consider technological innovation in the alternative, and we note that building block 1 encourages the spread of more advanced technology to EGUs currently using components with older designs.
As noted in the June 2014 proposal, the EPA is concerned about the potential “rebound effect” associated with building block 1 if applied in isolation. More specifically, we noted that in the context of the integrated electricity system, absent other incentives to reduce generation and CO
b.
The EPA's analysis and conclusions regarding the technical feasibility, costs, and magnitude of CO
Building block 2 is adequately demonstrated as a “system of emission reduction” for affected steam EGUs. As discussed in section V.B., since the time of the 1970 CAA Amendments, the utility power sector has recognized that generation shifts are a means of controlling air pollutants; in the 1990 CAA Amendments, Congress recognized that generation shifts among EGUs are a means of reducing emissions from this sector; and generation shifts similarly have been recognized as a means of reducing emissions under trading programs established by the EPA to implement the Act's provisions. It is common practice in the industry to account for the cost of emission allowances as a variable cost when making security-constrained, cost-based dispatch decisions; doing so integrates generation shifts into the operating practices used to achieve compliance with environmental requirements in an economical manner. These industry trends are further discussed in section V.D. Thus, legislative history, regulatory precedent, and industry practice support interpreting the broad term “system of emission reduction” as including substituting lower-emitting generation for higher-emitting generation through generation shifts among affected EGUs.
An important additional consideration supporting the determination that building block 2 is adequately demonstrated as a “system of emission reduction” is that owners of affected steam EGUs have the ability to invest in generation shifts as a way of reducing emissions. The owner of an affected EGU could invest in such generation shifts in several ways, including by increasing operation of an NGCC unit that it already owns or by purchasing an existing NGCC unit and increasing operation of that unit. Increases in generation by NGCC units over baseline levels can also serve as the basis for creation of CO
We note that an affected EGU investing in building block 2 to reduce emissions may, but need not, also choose to reduce its own generation as part of its approach for meeting the standard of performance assigned to it by its state. Through the coordinated operation of the integrated electricity system, subject to the collective emission reduction requirements that will be imposed on affected EGUs in order to meet the emissions standards representing the BSER, an increase in NGCC generation will be offset elsewhere in the interconnection by a decrease in other generation. Because of the need to meet the collective emission reduction requirements, the decrease in generation resulting from that coordinated operation is most likely to be generation from an affected steam EGU. Measures taken by affected EGUs that result in emission reductions from other EGUs in the source category may appropriately be deemed measures to implement or apply the “system of emission reduction” of substituting lower-emitting generation for higher-emitting generation.
Consideration of other BSER factors also supports a determination to include building block 2 as a component of the BSER. For example, we expect that building block 2 would have positive non-air health and environmental impacts. Coal combustion for electricity generation produces large volumes of solid wastes that require disposal, with some potential for adverse environmental impacts; these wastes are not produced by natural gas combustion. The intake and discharge of water for cooling at many EGUs also carries some potential for adverse environmental impacts; NGCC units generally require less cooling water than steam EGUs.
It should be observed that, by definition of the elements of this building block, the shifts in generation taking place under building block 2 occur entirely among existing EGUs subject to this rulemaking.
c.
The EPA's analysis and conclusions regarding the technical feasibility, costs, and magnitude of the measures in building block 3 are discussed in Section V.E. below. Additional analysis and conclusions with respect to cost reasonableness are discussed in section V.A.4.d. below. We consider construction and operation of expanded RE generating capacity to be proven, well-established practices within the industry consistent with recent industry trends. States are already pursuing policies that encourage production of greater amounts of RE, such as the establishment of targets for procurement of renewable generating capacity. Moreover, as discussed earlier, markets are likely to develop for ERCs that would facilitate investment in increased RE generation as a means of helping sources comply with their standards of performance; indeed, markets for RECs, which similarly facilitate investment in RE for other purposes, are already well-established. As noted in Section V.A.5. below, an allowance system or tradable emission rate system would provide incentives for affected EGUs to reduce their emissions as much as possible where such reductions could be achieved economically (taking into account the value of the emission credits or allowances), including by substituting generation from new RE generating capacity for their own generation, or could provide a mechanism, as stated above, for such sources to invest in or acquire such generation.
Building block 3 is adequately demonstrated as a “system of emission reduction” for all affected EGUs. As discussed in section II, RE generation has been relied on since the 1970s to provide energy security by replacing some fossil fuel-fired generation. Both Congress and the EPA have previously established frameworks under which RE generation could be used as a means of achieving emission reductions from the utility power sector, as discussed in section V.B. Investment in RE generation has grown rapidly, such that in recent years the amount of new RE generating capacity brought into service has been comparable to the amount of new fossil fuel-fired capacity. Rapid growth in RE generation is projected to continue as costs of RE generation fall relative to the costs of other generation technologies. These trends are further discussed in section V.E. Interpretation of a “system of emission reduction” as including RE generation for purposes of this rule is thus supported by legislative history, regulatory precedent, and industry practice.
Also supporting the determination that building block 3 is adequately demonstrated as a “system of emission reduction” is the fact that owners of affected EGUs have the ability to invest in RE generation as a way of reducing emissions. As with building block 2, this can be accomplished in several ways. For example, the owner of an affected EGU could invest in new RE generating capacity and operate that capacity in order to obtain ERCs. Alternatively, the affected EGU could purchase ERCs created based on the operation of an unaffiliated RE generating facility, effectively investing in the actions at another site that allow CO
As with building block 2, an affected EGU investing in building block 3 to reduce emissions may, but need not, also choose to reduce its own generation as part of its approach for meeting the standard of performance assigned to it by its state. Through the coordinated operation of the integrated electricity system, subject to the collective requirements that will be imposed on affected EGUs in order to meet the
The renewable capacity measures in building block 3 generally perform well against other BSER criteria. Generation from wind turbines and solar voltaic installations, two common renewable technologies, does not produce solid waste or require cooling water, a better environmental outcome than if that amount of generation had instead been produced at a typical range of fossil fuel-fired EGUs. With respect to energy impacts, fossil fuel consumption will decrease both for the source category as a whole and for individual affected EGUs. Although the variable nature of generation from renewable resources such as wind and solar units requires special consideration from grid operators to address possible changes in operating reserve requirements, renewable generation has grown quickly in recent years, as discussed above, and grid planners and operators have proven capable of addressing any consequent changes in requirements through ordinary processes. The EPA believes that planners and operators will be similarly capable of addressing any changes in requirements due to future growth in renewable generation through ordinary processes, but notes that in addition, the reliability safety valve in this rule, discussed in section VIII.G.2, will ensure the absence of adverse energy impacts. With respect to technological innovation, which we consider for the BSER only in the alternative, incentives for expansion of renewable capacity encourage technological innovation in improved renewable technologies as well as more extensive deployment of current advanced technologies. For all these reasons, the measures in building block 3 qualify as a component of the “best system of emission reduction . . . adequately demonstrated.”
d.
As already discussed, each of the individual building blocks generally performs well with respect to the BSER factors identified by the statute and the D.C. Circuit. (The exception, which we have pointed out above, is that building block 1, if implemented in isolation, would achieve an insufficient magnitude of emission reductions to be considered the BSER.) The EPA expects that combinations of the building blocks would perform better than the individual building blocks. Beginning with the most obvious and important advantage, combinations of the building blocks will achieve greater emission reductions than the individual building blocks would in isolation, assuming that the building blocks are applied with the same stringency. Because fossil fuel-fired EGUs generally have higher variable costs than other EGUs, it will generally be fossil fuel-fired generation that is replaced when low-variable cost RE generation is increased. At the levels of stringency determined to be reasonable in this rule, opportunities to deploy building block 2 to replace higher-emitting generation and to deploy building block 3 to replace any emitting generation are not exhausted. Thus, as the system of emission reduction is expanded to include each of these building blocks, the emission reductions that will be achieved increase.
Because the stringency and timing of emission reductions achievable through use of each individual building block have been set based on what is achievable at reasonable cost rather than the maximum achievable amount, the stringency of the combination of building blocks is also reasonable, and the combination provides headroom and additional flexibility for states in setting standards of performance and for sources in complying with those standards to choose among multiple means of reducing emissions.
With respect to the quantity of emission reductions expected to be achieved from building block 1 in particular, the BSER encompassing all three building blocks is a substantial improvement over building block 1 in isolation. As noted earlier, the EPA is concerned that implementation of building block 1 in isolation not only would achieve insufficient emission reductions assuming generation levels from affected steam EGUs were held constant, but also has the potential to result in a “rebound effect.” The nature of the potential rebound effect is that by causing affected steam EGUs to improve their heat rates and thereby lower their variable operating costs, building block 1 if implemented in isolation would make those EGUs more competitive relative to other, lower-emitting fossil fuel-fired EGUs, possibly resulting in increased generation and higher emissions from the affected steam EGUs in spite of their lower emission rates. Combining building block 1 with the other building blocks addresses this concern by ensuring that owner/operators of affected steam EGUs as a group would have appropriate incentives not only to improve the steam EGUs' efficiency but also to reduce generation from those EGUs consistent with replacement of generation by low- or zero-emitting EGUs. While combining building block 1 with either building block 2 or 3 should address this concern, the combination of all three building blocks addresses it more effectively by strengthening the incentives to reduce generation from affected steam EGUs.
The combination of all three building blocks is also of reasonable cost, for a number of independent reasons described below. The emission reductions associated with the BSER determined in this rule are significant, necessary, and achievable. As discussed in section V.A.1. above, the Administrator must take cost into account when determining that the measures constituting the BSER are adequately demonstrated, and the Administrator has done so here. Below, we summarize information on the cost of the building block measures and discuss the several independent reasons for the Administrator's determination that the costs of the building block 1, 2, and 3 measures, alone or in combination, are reasonable. In considering whether these costs are reasonable, the EPA considered the costs in light of both the observed and projected effects of GHGs in the atmosphere, their effect on climate, and
As described in sections V.C. through V.E. and the GHG Mitigation Measures TSD, the EPA has determined that the cost of each of the three building blocks is reasonable. In summary, these cost estimates are $23 per ton of CO
The EPA views the weighted average cost estimate as a conservatively high estimate of the cost of deploying all three building blocks simultaneously. The simultaneous application of all three building blocks produces interactive dynamics, some of which could increase the cost and some of which could decrease the cost represented in the individual building blocks. For example, one dynamic that would tend to raise costs (and whose omission would therefore make the weighted average understate costs) is that the emission reduction measures associated with building blocks 2 and 3 both prioritize the replacement of higher-cost generation (from affected steam EGUs in the case of building block 2 and from all affected EGUs in the case of building block 3). The EPA recognizes that the increased magnitude of generation replacement when building blocks 2 and 3 are implemented together necessitates that some of the generation replacement will occur at more efficient affected EGUs, at a relatively higher cost; however, this is a consequence of the greater emission reductions that can be achieved by combining building blocks, not an indication that any individual building block has become more expensive because of the combined deployment.
Also, the EPA recognizes that when building block 1 is combined with the other building blocks, the combination has the potential to raise the cost of the portion of the overall emission reductions achievable through heat rate improvements relative to the cost of those same reductions if building block 1 were implemented in isolation (assuming for purposes of this discussion that the rebound effect is not an issue and that the affected steam EGUs would in fact reduce their emissions if building block 1 were implemented in isolation).
In contrast with those prior examples, combining the building blocks also produces interactive dynamics that significantly reduce the cost for CO
The EPA believes the dynamics tending to cause the weighted average above to overstate costs of the combination of building blocks are greater than the dynamics tending to cause costs to be understated, and that the weighted average costs are therefore conservatively high. Analysis performed by the EPA at an earlier stage of the rulemaking supports this conclusion. At proposal, the EPA evaluated the cost of increasing NGCC utilization (building block 2) and deploying incremental RE generation (building block 3) independently, as well as the cost of simultaneously increasing NGCC utilization and incremental RE generation. The average cost (in dollars per ton of CO
A final reason why the EPA considers the weighted-average cost above conservatively high is that simply combining the building blocks at their full individual stringencies overstates the stringency of the BSER. As discussed in section V.A.3.f and section VI, the BSER reflects the combined degree of emission limitation achieved through application of the building blocks in the least stringent region. By definition, in the other two regions, the BSER is less stringent than the simple combination of the three building blocks whose stringency is represented in the weighted-average cost above.
The cost estimates for each of the three building blocks cited above—$23, $24, and $37 per ton of CO
In assessing cost reasonableness for the BSER determination for this rule, the EPA has compared the estimated costs discussed above to two types of cost benchmark. The first type of benchmark comprises costs that affected EGUs incur to reduce other air pollutants, such as SO
In comparison, we estimate that for a coal-fired steam EGU with a heat rate of 10,000 Btu per kWh, assuming the conservatively high cost of $30 per ton of CO
The second type of benchmark comprises CO
In addition to comparison to these benchmarks, there is a third independent way in which EPA has considered cost. In light of the severity of the observed and projected climate change effects on the U.S., U.S. interests, and U.S. citizens, combined with EGUs' large contribution to U.S. GHG emissions, the costs of the BSER measures are reasonable when compared to other potential control measures for this sector available under
As required under Executive Order 12866, the EPA conducts benefit-cost analyses for major Clean Air Act rules.
Finally, the EPA notes that the combination of all three building blocks would perform consistently with the individual building blocks with respect to non-air energy and environmental impacts. There is no reason to expect an adverse non-air environmental or energy impact from deployment of the combination of the three building blocks, whether considered on a source-by-source basis, on a sector-wide or national basis, or both. In fact, the combination of the building blocks, like the building blocks individually, as discussed above, would be expected to produce non-air environmental co-benefits in the form of reduced water usage and solid waste production (and, in addition to these non-air environmental co-benefits, would also be expected to reduce emissions of non-CO
e.
For these reasons, any combination of the building blocks (but not a BSER comprising building block 1 in isolation) could be the BSER if it were not for the fact that a BSER comprising all three of the building blocks will achieve greater emission reductions at a reasonable cost and is therefore “better.” As discussed below in section V.A.7., we intend for the individual building blocks to be severable, such that if a court were to deem building block 2 or 3 defective, but not both, the BSER would comprise the remaining building blocks.
f.
As noted, the building blocks include several features that assure that affected EGUs may implement them. The building blocks may be implemented through a range of methods, including through the purchase of ERCs and emission trading. In addition, the building blocks incorporate “headroom.” Moreover, the source subcategory-specific emission performance rates apply on an annual or longer basis, so that short-term issues need not jeopardize compliance. In addition, we quantify the emission performance rates based on the degree of emission limitation achievable by affected EGUs in the region where application of the combined building blocks results in the least stringent emission rate. Because the means to implement the building blocks are widely available and because of the just-noted flexibilities and approaches to the emission performance rates, all types of affected steam generating units, operating throughout the lower-48 states and under all types of regulatory regimes, are able to implement building blocks 1, 2 and 3 and thereby achieve the emission performance rate for fossil steam units, and all types of NGCC units operating in all states under all types of regulatory requirements are able to implement building block 3 and thereby achieve the emission performance rate for NGCC units.
Commenters have raised questions about whether particular circumstances could arise, such as the sudden loss of certain generation assets, that would cause the implementation of the building blocks to cause reliability problems, and have cautioned that these circumstances could preclude implementation of the building blocks and thus achievement of the emission performance rates. Commenters have also raised concerns about whether affected EGUs with limited remaining useful lives can implement the building blocks and achieve the emission performance rates. We address those concerns in section VIII, where we authorize state plans to include a reliability mechanism and discuss affected EGUs with limited remaining useful lives. Accordingly, we conclude that the source subcategory-specific emission performance standards are achievable in accordance with the case law.
Based on the determination of the BSER described above, the EPA has identified a performance rate of 1305 lbs. per net MWh for affected steam EGUs and a performance rate of 771 lbs. per net MWh for affected stationary combustion turbines. The computations of these performance rates and the determinations of state goals reflecting these rates are described in sections VI and VII of the preamble, respectively.
Under section 111(d), states determine the standards of performance for individual sources. The EPA is authorizing states to express the standards of performance applicable to affected EGUs as either emission rate-based limits or mass-based limits. As described above, the sets of actions that sources can take to comply with these standards implement or apply the BSER and, in that sense, may be understood as part of the BSER.
A source to which a state applies an emission rate-based limit can achieve the limit through a combination of the following set of measures (to the extent allowed by the state plan), all of which are components of the BSER, again, in the sense that they implement or apply it:
• Reducing its heat rate (building block 1).
• Directly investing in, or purchasing ERCs created as a result of, incremental generation from existing NGCC units (building block 2).
• Directly investing in, or purchasing ERCs created as a result of, generation from new or uprated RE generators (building block 3).
• Reducing its utilization, coupled with direct investment in or purchase of ERCs representing building blocks 2 and 3 as indicated above.
• Investing in surplus emission rate reductions at other affected EGUs through the purchase or other acquisition of rate-based emission credits.
A source to which a state applies a mass-based limit can achieve the limit through a combination of the following set of measures (to the extent allowed by the state plan), all of which are likewise components of the BSER:
• Reducing its heat rate (building block 1).
• Reducing its utilization and allowing its generation to be replaced or avoided through the routine operation of industry reliability planning mechanisms and market incentives.
• Investing in surplus emission reductions at other affected EGUs through the purchase or other acquisition of mass-based emission allowances.
The EPA has determined appropriate CO
In the remainder of this subsection, we discuss further how affected EGUs can use each of the measures listed above to achieve emission rate-based forms of performance standards and mass-based forms of performance standards, indicating that all types of owner/operators of affected EGUs—
a.
In section VIII.K, we discuss the processes for issuance and use of ERCs that can be included in the emission rate computations that affected EGUs perform to demonstrate compliance with an emission rate standard. This ERC mechanism is analogous to the approach the EPA has used to reflect building blocks 2 and 3 in the uniform emission rates representing the BSER, as discussed in section VI below. As summarized below and as discussed in greater detail in section VIII.K, the existence of a clearly feasible path for usage of ERCs ensures that emission reductions achievable through implementation of the measures in building blocks 2 and 3 are available to assist all affected EGUs in achieving compliance with standards of performance based on the BSER.
(1)
The owner/operator of an affected steam EGU can take steps to reduce the unit's heat rate, thereby lowering the unit's CO
(2)
The owner/operator of an affected EGU can average the EGU's emission rate with ERCs issued on the basis of incremental generation from an existing NGCC unit. As permitted under the EGU's state's section 111(d) plan, the owner/operator of the affected EGU could accomplish this through either common ownership of the NGCC unit, a bilateral transaction with the owner/operator of the NGCC unit, or a transaction for ERCs through an intermediary, which could but need not involve an organized market.
In section VIII.K below, the EPA sets out the minimum criteria that must be satisfied for generation and issuance of a valid ERC based upon incremental electricity generation by an existing NGCC unit. Those criteria generally concern ensuring that the physical basis for the ERC—
The owner/operator of an affected steam EGU would use the ERCs it has acquired for compliance—whether acquired through ownership of NGCC capacity, a bilateral transaction, or an intermediated transaction—by adding the ERCs to its measured net generation when computing its CO
(3)
The owner/operator of an affected EGU can average the EGU's emission rate with ERCs issued on the basis of generation from new (
In section VIII.K below, the EPA sets out the minimum criteria that must be satisfied for generation and issuance of a valid ERC based upon generation from new RE generating capacity. Those criteria generally concern assuring that the physical basis for the ERC—
As with building block 2, the owner/operator of an affected EGU would use the ERCs it has acquired for compliance—whether acquired through ownership of qualifying RE generating capacity, a bilateral transaction, or an intermediated transaction—by adding the ERCs to its measured net generation when computing its CO
(4)
The owner/operator of an affected EGU can reduce the unit's generation and reflect that reduction in the form of a lower emission rate provided that the owner/operator also acquires some amount of ERCs to use in computing the unit's emission rate for purposes of demonstrating compliance. As
(5)
To the extent allowed under standards of performance that incorporate emissions trading or otherwise through the relevant section 111(d) plans, the owner/operator of an affected EGU can acquire tradable rate-based emission credits representing an investment in surplus emission rate reductions not needed by another affected EGU and can average those credits into its own emission rate for purposes of demonstrating compliance with its rate-based standard of performance. The approach would have to be authorized in the appropriate section 111(d) plan and would have to conform to the minimum conditions for such approaches described in section VIII below. As we have repeatedly noted, based on our reading of the comment record and the discussions that occurred during the outreach process, it is reasonable to presume that such authorization will be forthcoming from states that submit plans establishing rate-based standards of performance for their affected EGUs.
Under a rate-based emissions trading approach, credits are initially created and issued according to processes defined in the state plan. After credits are initially issued, the owner/operator of an affected EGU needing additional credits can acquire credits through common ownership of another affected EGU or through a bilateral transaction with the other affected EGU, or the owner/operator of the affected EGU can acquire credits in a transaction through an intermediary, which could, but need not, involve an organized market. As discussed earlier, based on observation of market behavior both inside and outside the electricity industry, we expect that intermediaries will seek opportunities to participate in such transactions and that organized markets are likely to develop as well if section 111(d) plans and/or standards of performance established thereunder authorize emissions trading. While the opportunity to acquire credits through common ownership might not extend to owner/operators of single EGUs or small fleets, all owner/operators would have the ability to engage in bilateral or intermediated purchase transactions for credits just as they can engage in transactions for other kinds of goods and services.
Further details regarding the possible use of rate-based emission credits in a state plan (using ERCs issued on the basis of investments in building blocks 2 and 3 and potentially other measures as the credits) are provided in section VIII.K.
b.
Measurements of mass emissions at a given affected EGU capture reductions in the EGU's emissions arising from both reductions in generation and reductions in the emission rate per MWh. Accordingly, under a mass-based standard there is no need to provide a mechanism such as the ERC mechanism described above in order to properly account for emission reductions attributable to particular types of BSER measures. The relative simplicity of the mechanics of monitoring and determining compliance are significant advantages inherent in the use of mass-based standards rather than emission rate-based standards.
(1)
The owner/operator of an affected steam EGU can take steps to reduce the unit's heat rate, thereby lowering the unit's CO
(2)
The owner/operator of an affected EGU can reduce its generation, thereby lowering the unit's CO
Of course, if the owner/operator of the affected EGU wishes to play a direct role in driving the increase in lower-carbon generation or demand-side EE required to offset a reduction in the affected EGU's generation, the owner/operator may do so as part of whatever role it happens to play as a participant in the interconnected electricity system. However, the owner/operator will achieve the benefit that reduction in generation brings toward compliance with the mass-based standard whether it takes those additional actions itself or instead allows other participants in the interconnected electricity system to play that role.
(3)
To the extent allowed under the relevant section 111(d) plans—as the record indicates that it is reasonable to expect it will be—the owner/operator of an affected EGU can acquire tradable mass-based emission allowances representing investment in surplus emission reductions not needed by another affected EGU and can aggregate those allowances with any other
Under a mass-based emissions trading approach, the total number of allowances to be issued is defined in the state plan, and affected EGUs may obtain an initial quantity of allowances through an allocation or auction process. After that initial process, the owner/operator of an affected EGU needing additional allowances can acquire allowances through common ownership of another affected EGU or through a bilateral transaction with the other affected EGU, or the owner/operator of the affected EGU can acquire allowances in a transaction through an intermediary, which could but need not involve an organized market. As discussed earlier, based on observation of market behavior both inside and outside the electricity industry, we expect that intermediaries will seek opportunities to participate in such transactions and that organized markets are likely to develop as well if section 111(d) plans authorize the use of emissions trading. While the opportunity to acquire allowances through common ownership might not extend to owner/operators of single EGUs or small fleets, all owner/operators would have the ability to engage in bilateral or intermediated purchase transactions for allowances just as they can engage in transactions for other kinds of goods and services.
Further details regarding the possible use of mass-based emission allowances in a state plan are provided in section VIII.J.
In addition to the BSER-related measures that affected EGUs can use to achieve the standards of performance set in section 111(d) plans, there are a variety of non-BSER measures that could also be employed (to the extent permitted under a given plan). This final rule does not limit the measures that affected EGUs may use for achieving standards of performance to measures that are included in the BSER; thus, the existence of these non-BSER measures provides flexibility allowing the individual affected EGUs and the source category to achieve emission reductions consistent with application of the BSER at the levels of stringency reflected in this final rule even if one or more of the building blocks is not implemented to the degree that the EPA has determined to be reasonable for purposes of quantifying the BSER. In this way, non-BSER measures provide additional flexibility to states in establishing standards of performance for affected EGUs through section 111(d) plans and to individual affected EGUs for achieving those standards.
Any of the non-BSER measures described below would help the affected source category as a whole achieve emission limits consistent with the BSER. The non-BSER measures either reduce the amount of CO
In general, a non-BSER measure that reduces the amount of CO
Other non-BSER measures do not reduce an affected EGU's CO
Under an emission rate-based standard, non-BSER measures that reduce generation from affected EGUs but do not reduce an affected EGU's emission rate generally can facilitate compliance by serving as the basis for ERCs that affected EGUs can average into their emission rates for purposes of demonstrating compliance. Section VIII.K. includes a discussion of the issuance of ERCs based on various non-BSER measures. Affected EGUs could use such ERCs to the extent permitted by the relevant section 111(d) plans.
The remainder of this section discusses some specific types of non-BSER measures. The first set discussed includes measures that can reduce the amount of CO
a.
In the final rule, the EPA has reached determinations consistent with the proposal with respect to these measures: namely, that they do not merit inclusion in the BSER, but that they are capable of helping affected EGUs achieve compliance with standards of performance and are likely to be used for that purpose by some units. To the extent that they are selectively employed, they provide flexibility for the source category as a whole and for individual affected EGUs to achieve emission limits reflective of the BSER, as discussed above.
(1)
Building block 1 reflects the opportunity to improve heat rate at coal-fired steam EGUs but not at other affected EGUs. As the EPA stated at proposal, the potential CO
(2)
Another approach for reducing CO
(3)
In the proposal we discussed the opportunity to reduce CO
Some owner/operators are already converting some affected EGUs from coal to natural gas, and it is apparent that the measure can be attractive compared to alternatives in certain circumstances, such as when a unit must meet tighter unit-specific limits on emissions of non-GHG pollutants, the options for meeting those emission limits are costly, and retirement of the unit would necessitate transmission upgrades that are costly or cannot be completed quickly. CO
(4)
Some affected EGUs may seek to co-fire qualified biomass with fossil fuels. The EPA recognizes that the use of some biomass-derived fuels can play an important role in controlling increases of CO
(5)
Certain affected EGUs in urban areas or located near industrial or commercial facilities with needs for thermal energy may be able add new equipment to capture some of the waste heat from their electricity generation processes and use it to create useful thermal output, thereby engaging in combined heat and power (CHP) production. While the set of affected EGUs in locations making this measure feasible may be limited, where feasible the potential CO
b.
A second group of non-BSER measures has the potential to reduce CO
(1)
One of the major approaches available for achieving CO
For the reasons discussed in section V.B.3.c.(8) below, the EPA has determined not to include demand-side EE in the BSER in this final rule. However, the final rule authorizes generation avoided through investments in demand-side EE to serve as the basis for issuance of ERCs when appropriate conditions are met. In section VIII.K below, the EPA sets out the minimum criteria that must be satisfied for generation and issuance of a valid ERC based upon implementation of new demand-side EE programs. Those criteria generally concern ensuring that the physical basis for the ERC—in this case, generation avoided through implementation of demand-side EE measures—is adequately evaluated, measured, and verified and that there is an adequate administrative process for tracking credits.
Through their authority over legal requirements such as building codes, states have the ability to drive certain types of demand-side EE measures that are beyond the reach of private-sector entities. The EPA recognizes that, by definition, this type of measure is beyond the ability of affected EGUs to invest in either directly or through bilateral arrangements. However, the final rule also authorizes generation avoided through such state policies to serve as the basis for issuance of ERCs that in turn can be used by affected EGUs. The section 111(d) plan would need to include appropriate provisions for evaluating, measuring, and verifying the avoided MWh associated with the state policies, consistent with the criteria discussed in section VIII.K below.
(2)
In the June 2014 proposal, the EPA included generation from the five nuclear units currently under construction as part of the proposed BSER. As discussed above in section V.A.3.c., upon consideration of comments, we have determined that generation from these units should not be part of the BSER. However, we continue to observe that the zero-emitting generation from these units would be expected to replace generation from affected EGUs and thereby reduce CO
(3)
The range of available zero-emitting RE generating technologies is broader than the range of RE technologies determined to be suitable for use in quantification of building block 3 as an element of the BSER. Examples of additional zero-emitting RE technologies not included in the BSER that could be used to achieve emission limits consistent with the BSER include offshore wind, distributed solar, and fuel cells. These technologies were not included in the range of RE technologies quantified for the BSER because they are generally more expensive than the measures that were included and the other measures in the BSER. However, these technologies are equally capable of replacing generation from affected EGUs and thereby reducing CO
(4)
Generation from new or expanded facilities that combust qualified biomass or biogenic portions of municipal solid waste (MSW) to produce electricity can also replace generation from affected EGUs and thereby control CO
(5)
Industrial facilities that install new equipment to capture waste heat from an existing combustion process and then use the waste heat to generate electricity—a form of combined heat and power (CHP) production—can produce generation that replaces generation from affected EGUs and thereby reduces CO
(6)
Reductions of electricity line losses incurred from the transmission and distribution system between the points of generation and the points of consumption by end-users allow the same overall demand for electricity services to be met with a smaller overall quantity of electricity generation. Such reductions in generation quantities would tend to reduce generation by affected EGUs, thereby reducing CO
The EPA intends that the components of the BSER summarized above be severable. It is reasonable to consider the building blocks severable because the building blocks do not depend on one another. Building blocks 2 and 3 are feasible and demonstrated means of reducing CO
Further, building block 2, building block 3, and all combinations of the building blocks (implemented on the schedules and at the stringencies determined to be reasonable in this rule) would achieve meaningful degrees of emission reductions,
In the event that a court should deem building block 2 or 3 defective, but not both, the standards and state goals can be recomputed on the basis of the remaining building blocks. All of the data and procedures necessary to determine recomputed state goals using any combination of the building blocks are set forth in the CO
This section includes a legal analysis of various aspects of EPA's determination of the BSER, including responses to some of the major adverse comments. These aspects include (1) the EPA's authority to determine the BSER; (2) the approach to subcategorization; (3) the EPA's basis for determining that building blocks 2 and 3 qualify as part of the BSER under CAA sections 111(d)(1) and (a)(1), notwithstanding commenters' arguments that these building blocks cannot be considered part of the BSER because they are not based on measures integrated into the design or operation of the affected source's own production processes or methods or because they are dependent on actions by entities other than the affected source; (4) the relationship between an affected EGU's implementation of building blocks 2 and 3 and CO
In this section, we explain why the EPA, and not the states, has the authority to determine the BSER and, therefore, the level of emission limitation required from the existing sources in the source category in section 111(d) rulemaking and the associated state plans.
CAA section 111(d)(1) requires the EPA to establish a section 110-like procedure under which each state submits a plan that “establishes standards of performance for any existing source of air pollutant” and “provides for the implementation and enforcement of such standards of performance.” As CAA section 111(d) was originally adopted in the 1970 CAA Amendments, however, state plans were required to establish “emission standards”—an undefined term—rather than “standards of performance,” a term that was limited to CAA section 111(b).
These regulations establish a cooperative framework that is similar to that under CAA section 110. First, the EPA develops “emission guidelines” for source categories, which are defined as a final guideline document reflecting “the degree of emission reduction achievable through the application of the best system of emission reduction . . . which the Administrator has determined has been adequately demonstrated.” Then, the states submit implementation plans to regulate any existing sources.
The preamble to these regulations carefully considered the allocation of responsibilities as between the EPA and the states for purposes of CAA section 111(d), and concluded that the EPA is responsible for determining the level of emission limitation from the source category, while the states have the responsibility of assigning emission requirements to their sources that assured their achievement of that level of emission limitation.
In 1977, Congress revised CAA section 111(d) to require that the states adopt “standards of performance,” as defined under CAA section 111(a)(1). As noted above, a standard of performance is defined as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which . . .
In addition, in the legislative history of the 1977 CAA Amendments, when Congress replaced the term “emission standards” under CAA section 111(d)(1) with the term “standards of performance,” Congress endorsed the overall approach of the implementing regulations, which lends further credence to the proposition that the EPA has the responsibility for determining the “best system of emission reduction” and the amount of emission limitation from the existing sources. Specifically, in the House report that introduced the substantive changes to CAA section 111, the Committee explained that “[t]he Administrator would establish
In addition, Congress expressly referred to our “guidelines” in CAA section 129, added as part of the 1990 CAA Amendments. Congress added CAA section 129 to address solid waste combustion and specifically directed the Administrator to establish “
The EPA has followed the same approach described in the implementation regulations in all its rulemakings under section 111(d). Thus, in all cases, the EPA has identified the type of emission controls for the source category and the level of emission limitation based on those controls.
Lastly, this interpretation is consistent with the Supreme Court's reading of CAA section 111(d) in
As noted in the response to comment document, some commenters agreed with our interpretation, just discussed, while others argued that the states should be given the authority to determine the best system of emission reduction and, therefore, the level of emission limitation from their sources. For the reasons just discussed, this latter interpretation is an incorrect interpretation of CAA section 111(d)(1) and (a)(1), and we are not compelled to abandon our longstanding practice.
As noted above, in this rule, we are treating all fossil fuel-fired EGUs as a single category, and, in the emission
This approach is fully consistent with the provisions of section 111(d), which simply require the EPA to determine the BSER, do not prescribe the method for doing so, and are silent as to subcategorization. This approach is also fully consistent with other provisions in CAA section 111, which require the EPA first to list source categories that may reasonably be expected to endanger public health or welfare
For this rule, our approach of subcategorizing between steam EGUs and combustion turbines is reasonable because building blocks 1 and 2 apply only to steam EGUs. No further subcategorization is appropriate because each affected EGU can achieve the performance rate by implementing the BSER. Specifically, as noted, each affected EGU may take a range of actions including investment in the building blocks, replacing or reducing generation, and emissions trading, as enabled or facilitated by the implementation programs the states adopt. Further, in the case of a rate-based state plan, several other compliance options not included in the BSER for this rule are also available to all affected sources, including investment in demand-side EE measures. Such compliance options help affected sources achieve compliance under a mass-based plan, even if indirectly. Our approach to subcategorization in this rule is consistent with our approach to subcategorization in previous section 111 rules for this industry, in which we determined whether or not to subcategorize on the basis of the ability of affected EGUs with different characteristics (
In addition, there are numerous possible criteria to use in subcategorizing, including, among others, subcategorizing on the basis of age; size; steam conditions (
In addition, a section 111(d) rule presents less of a need to subcategorize because the states retain great flexibility in assigning standards of performance to their affected EGUs. Thus, a state can, if it wishes, impose different emission reduction obligations on its sources, as long as the overall level of emission limitation is at least as stringent as the emission guidelines, as discussed below. This means that if a state is concerned that its different sources have different capabilities for compliance, it can adjust the standards of performance in imposes on its sources accordingly.
a.
As we explain above, the emission performance rates that we include in this rule's emission guidelines are achievable by the affected EGUs through the application of the BSER, which includes the three building blocks. Commenters object that building blocks 2 (generation shift) and 3 (RE) cannot, as a legal matter, be considered part of the BSER under CAA section 111(d)(1) and (a)(1). These commenters explain that in their view, under CAA section 111, the emission performance rates must be based on, and therefore the BSER must be limited to, methods for emission control that the owner/operator of the affected source can integrate into the design or operation of the source itself, and cannot be based on actions taken beyond the source or actions involving third-party entities.
We disagree with these comments, and note that other commenters were supportive of our determination to include building blocks 2 and 3. Under CAA section 111(d)(1) and (a)(1), the EPA's emission guidelines must establish achievable emission limits based on the “best system of emission reduction . . . adequately demonstrated.” While some commenters assert that emission guidelines must be limited in the manner summarized above, the phrase “system of emission reduction,” by its terms and when read in context, contains no such limits. To the contrary, its plain meaning is deliberately broad and is capacious enough to include actions taken by the owner/operator of a stationary source designed to reduce emissions from that affected source, including actions that may occur off-site and actions that a third party takes pursuant to a commercial relationship with the owner/operator, so long as those actions enable the affected source to achieve its emission limitation. Such actions include the measures in building blocks 2 and 3, which, when implemented by an affected source, enable the source to achieve their emission limits because of the unique characteristics of the utility power sector. For purposes of this rule, we consider a “system of emission reduction”—as defined under CAA section 111(a)(1) and applied under CAA section 111(d)(1)—to encompass a broad range of pollution-reduction actions, which includes the measures in building blocks 2 and 3. Furthermore, the measures in building blocks 2 and 3 fall squarely within EPA's historical interpretation of section 111, pursuant to which the focus for the BSER has been on how to most cleanly produce a good, not on how much of the good should be produced.
Our interpretation that a “system of emission reduction” is broad enough to include the measures in building blocks 2 and 3 is supported by the following: Our interpretation of the phrase “system of emission reduction” is consistent with its plain meaning and statutory context; our interpretation accommodates the very design of CAA section 111(d)(1), which covers a range of source categories and air pollutants;
In addition to the reasons stated above, the EPA's interpretation is also reasonable for the following reasons: (i) Building blocks 2 and 3 fit well within the structure and economics of the utility power sector. (ii) Fossil fuel-fired EGUs are already implementing the measures in these building blocks for various reasons, including for purposes of reducing CO
Congress passed the CAA, including its several amendments, to protect public health and welfare from “mounting dangers,” including “injury to agricultural crops and livestock, damage to and the deterioration of property, and hazards to air and ground transportation.”
Although the BSER provisions are sufficiently broad to include, for affected EGUs, the measures in building blocks 2 and 3, they also incorporate significant constraints on the types of
b.
(1)
The phrase “system of emission reduction” appears in the definition of a “standard of performance” under CAA section 111(a)(1). That definition reads:
Although a “system of emission reduction” lays the groundwork for CAA section 111 standards, the term “system” is not defined in the CAA. As a result, we look first to its ordinary meaning.
Abstractly, the term “system” means a set of things or parts forming a complex whole; a set of principles or procedures according to which something is done; an organized scheme or method; and a group of interacting, interrelated, or interdependent elements.
When read in context, the phrase “system of emission reduction” carries important limitations: because the “degree of emission limitation” must be “
As a practical matter, the “source” includes the “owner or operator” of any building, structure, facility, or installation for which a standard of performance is applicable. For instance, under CAA section 111(e), it is the “owner or operator” of a source who is prohibited from operating “in violation of any standard of performance applicable to such source.”
Thus, a “system of emission reduction” for purposes of CAA section 111(d) means a set of measures that source owners or operators can implement to achieve an emission limitation applicable to their existing source.
In contrast, a “system of emission reduction” does not include actions that only a state or other governmental entity could take that would have the effect of reducing emissions from the source category, and that are beyond the ability of the affected sources' owners/operators to take or control. Additionally, actions that a source owner or operator could take that would not have the effect of reducing emissions from the source category, such as purchasing offsets, would also not qualify as a “system of emission reduction.”
Building blocks 2 and 3 each fall within the meaning of a “system of emission reduction” because they consist of measures that the owners/operators of the affected EGUs can implement to achieve their emission limits. In doing so, the affected EGUs will achieve the overall emission reductions the EPA identifies in this rule. We describe these building block 2 and 3 measures in detail elsewhere in this rule, including the specific actions that owners/operators of affected EGUs can take to implement the measures.
It should be noted that defining the scope of a “system of emission reduction” is not the end of our inquiry under CAA section 111(a)(1); rather, as noted above, a standard of performance must reflect the application of the “
For purposes of this final rule, it is not necessary to enumerate all of the types of measures that do or do not constitute a “system of emission reduction.” What is relevant is that building blocks 2 and 3 each qualify as part of the “system of emission reduction.” As noted, they focus on supply-side activities and they each constitute measures that the affected EGUs can implement that will allow those EGUs to achieve the degree of emission limitation that the EPA has identified based on those building blocks. Further, these building blocks also satisfy the other statutory criteria enumerated in CAA section 111(a)(1).
(2)
The EPA's plain meaning interpretation that the BSER provisions in CAA section 111(d)(1) and (a)(1) are designed to include a broad range of measures, including building blocks 2 and 3, is supported by several other indications in the CAA and the legislative history of section 111.
(a)
First, the broad scope of CAA section 111(d)(1) supports our interpretation of the BSER because a wide range of control measures is appropriate for the wide range of source categories and air pollutants covered under CAA section 111(d).
In the 1970 CAA Amendments, Congress established a regulatory regime for existing stationary sources of air pollutants that may be envisioned as a three-legged stool, designed to address “three categories of pollutants emitted from stationary sources”: (1) Criteria pollutants (identified under CAA section 109 and regulated under section 110); (2) hazardous air pollutants (identified and regulated under section 112); and (3) “pollutants that are (or may be) harmful to public health or welfare but are not” criteria or hazardous air pollutants.
Because Congress designed CAA section 111(d) to cover a wide range of air pollutants—including ones that Congress may not have been aware of at the time it enacted the provision—and a wide range of industries, it is logical that Congress intended that the BSER provision, as applied to CAA section 111(d), have a broad scope so as to accommodate the range of air pollutants and source categories.
(b)
(i)
The phrase “system of emission reduction,” particularly as applied under CAA section 111(d), should be broadly interpreted consistent with its plain meaning but also in light of its legislative history. The version of CAA section 111(d)(1) that Congress adopted as part of the 1970 CAA Amendments read largely as CAA section 111(d)(1) does at present, except that it required states to impose “emission standards” on any existing source. (Congress replaced that term with “standards of performance” in the 1977 CAA Amendments.) The 1970 CAA Amendments version of CAA section 111(d)(1) neither defined “emission standards” nor imposed restrictions on the EPA in determining the basis for the emission standards.
For new sources, CAA section 111(b)(1)(B), as enacted in the 1970 CAA Amendments (and as it largely still
The House and Senate bills do, however, provide some insights. The House bill, H.R. 17255, would have required new sources of non-hazardous air pollutants to “prevent and control such emissions to the fullest extent compatible with the available technology and economic feasibility, as determined by the Secretary.”
Following the House-Senate Conference, the enacted version of the legislation defined a “standard of performance” to mean
Notwithstanding this broad approach, as we discuss in the Legal Memorandum, the legislative history of the 1970 CAA Amendments also indicates that Congress intended that new sources be well-controlled at the source, in light of their expected lengthy useful lives.
In 1977, Congress amended CAA section 111(a)(1) to limit the types of controls that could be the basis of standards of performance for new sources to technological controls. Congress was clear, however, that existing source standards, which were no longer developed as “emission standards,” would not be limited to technological measures. Specifically, the 1977 CAA Amendments revised CAA section 111(a)(1) to require all new sources to meet emission standards based on the reductions achievable through the use of the “best technological system of continuous emission reduction.”
Despite these changes with respect to new sources, the 1977 CAA Amendments further reinforce the
In the 1990 CAA Amendments, Congress restored the 1970s vintage definition of a standard of performance as applied to both new and existing sources. With respect to existing sources, this had the effect of no longer requiring that the BSER be “continuous.”
That term continues to be used in reference to new sources in certain circumstances, under CAA section 111(b), (h), and (j).
For these reasons, the 1970, 1977, and 1990 legislative histories support the EPA's interpretation in this rule that the term is sufficiently broad to encompass building blocks 2 and 3.
(ii)
The legislative history supports the EPA's interpretation of “system of emission reduction” in another way as well: The legislative history makes clear that Congress intended that standards of performance for electric power plants could be based on measures implemented by other entities, for example, entities that “wash,” or desulfurize, coal (or, for oil-fired EGUs, that desulfurize oil). This legislative history is consistent with the EPA's view that the “system of emission reduction” may include actions taken by an entity with whom the owner/operator of the affected source enters into a contractual relationship as long as those actions allow the affected source to meet its emission limitation. By the same token, this legislative history directly refutes commenters' assertions that the phrase “system of emission reduction” must not include actions taken by entities other than the affected sources.
As noted above, in the 1977 CAA Amendments, Congress revised the basis for standards of performance for new fossil fuel-fired stationary sources to be a “technological system of continuous emission reduction,” including “precombustion cleaning or treatment of fuels.”
In the 1990 CAA Amendments, Congress eliminated many of the restrictions and other provisions added in the 1977 CAA Amendments by largely reinstating the 1970 CAA Amendments' definition of “standard of performance.” Nevertheless, there is no indication that in doing so, Congress intended to preclude the EPA from considering coal cleaning by third parties (which had been considered within the scope of the best system of emission reduction even under the 1970 CAA Amendments),
(c)
Interpreting CAA section 111(d)(1) and (a)(1) to authorize the EPA's consideration of the building block 2 and 3 measures is consistent with the overall structure of the CAA, particularly as it was amended in 1970, when Congress added CAA section 111 in much the same form that it reads today.
In the 1970 CAA Amendments, for the most part, and particularly for stationary source provisions, Congress painted with broad brush strokes, giving broad authority to the EPA or the states. That is, Congress established general requirements that were intended to produce stringent results, but gave the EPA or the states great discretion in fashioning the types of measures to achieve those results.
For example, under CAA section 109, Congress authorized the EPA to promulgate national ambient air quality standards (NAAQS) for air pollutants, and Congress established general criteria and procedural requirements, but left to the EPA discretion to identify the air pollutants and select the standards. Under CAA section 110, Congress required the states to submit to the EPA SIPs, required that the plans attain the NAAQS by a date certain, and established procedural requirements, but allowed the states broad discretion in determining the substantive requirements of the SIPs.
Under CAA section 111(b), Congress directed the EPA to list source categories that endanger public health or welfare and established procedural requirements, but did not include other substantive requirements, and instead gave the EPA broad discretion to determine the criteria for endangerment.
Under CAA section 112, Congress required the EPA to regulate certain air pollutants and to set “emission standards” that meet general criteria, and established procedural requirements, but did not include other substantive requirements and, instead, gave the EPA broad discretion in identifying the types of pollutants and in determining the standards.
Congress drafted the CAA section 111(d) requirements in the 1970 CAA Amendments, and revised them in the 1977 CAA Amendments, in a manner that is similar to the other stationary source requirements, just described, in CAA sections 109, 110, 111(b), and 112. The CAA section 111(d) requirements are broadly phrased, include procedural requirements but no more than very general substantive requirements, and give broad discretion to the EPA to determine the basis for the required emission limits and to the states to set the standards. It should be noted that this drafting approach is not unique to the CAA; on the contrary, Congress “usually does not legislate by specifying examples, but by identifying broad and general principles that must be applied to particular factual instances.”
In light of this statutory framework, it is clear that Congress delegated to the EPA the authority to administer CAA section 111, including by authorizing the EPA to apply the “broad and general principles” contained in CAA section 111(a)(1) to the particular circumstances we face today.
(3)
While some commenters support the EPA's interpretation of section 111 to authorize the inclusion of building blocks 2 and 3 in the BSER, other commenters assert that the emission standards must be based on measures that the sources subject to CAA section 111—in this rule, the affected EGUs—apply to their own design or operations, and, as a result, in this rule, cannot include measures implemented at entities other than the affected EGUs that have the effect of reducing generation, and therefore emissions, from the affected EGUs. The commenters assert that various provisions in CAA section 111 make this limitation clear. We do not find those arguments persuasive.
First, some commenters state that under CAA section 111(d)(1) and (a)(1), the existing sources subject to the standards of performance must be able to achieve their emission limit, but that they are able to do so only through measures integrated into the source's own design and operation. As a result, according to these commenters, those are the only types of measures that may qualify as a “system of emission reduction” that may form the basis of the emissions standards. We disagree. We see nothing in CAA section 111(d)(1) or (a)(1) which by its terms limits CAA section 111 to measures that must be integrated into the sources' own design or operation. Rather, we recognize that in order for an emission limitation based on the BSER to be “achievable,” the BSER must consist of measures that can be undertaken by an affected source—that is, its owner or operator. As noted elsewhere in the
The broad nature of CAA section 111(d)(1) and (a)(1) is also confirmed by comparing it to CAA provisions that explicitly require controls on the design or operations of an affected source. The most notable comparison is at CAA section 111(a)(7). The term “technological system of continuous emission reduction,” which was added in 1977 and remains as a separately defined term means, in part, “a technological process
Several other examples of standard setting in the CAA shed light on ways in which Congress has constrained the EPA's review. CAA section 407(b)(2) provides that the EPA base NO
Some commenters also argue that other provisions in CAA section 111 indicate that Congress intended that CAA section 111(d)(1) and (a)(1) be limited to measures that are integrated into the source's design or operations. This argument is unpersuasive for several reasons. First, it would be unreasonable to presume that Congress intended to limit the BSER, indirectly through these other provisions, to measures that are integrated into the affected source's design or operations, when Congress could have done so expressly, as it did for the above-discussed CAA section 407(b)(2) NO
Second, the interpretations that commenters offer for these various provisions misapply the text. For example, commenters note that under CAA section 111(d)(1), (a)(3), and (a)(6), the standards of performance apply to “any existing source,” and an “existing source” is defined to include “any stationary source,” which, in turn, is defined as “any building, structure, facility, or installation which emits or may emit any air pollutant.” Commenters assert that these applicability and definitional provisions indicate that the BSER provisions in CAA section 111(d)(1) and (a)(1) must be interpreted to require that the control measures must be integrated into the design or operations of the source itself.
We disagree. These applicability and definitional provisions are jurisdictional in nature. Their purpose is simply to identify the types of sources whose emissions are to be addressed under CAA section 111(d),
These applicability and definitional provisions say nothing about the system of emission reduction—whether it is limited to measures integrated into the design or operation of the source itself or may be broader—that may form the basis of the standards for those emissions that are to be promulgated under CAA section 111.
Third, this argument by commenters does not account for the commonsense proposition that it is the owner/operator of the stationary source, not the source itself, who is responsible for taking actions to achieve the emission rate, so that actions that the owner/operator is able to take should be considered in determining the appropriate standards for the source's emissions. Again, it is common sense that buildings, structures, facilities, and installations can take no actions—only owners and operators can install and maintain pollution control equipment; only owners and operators can solicit precombustion cleaning or treatment of fuel services; and only owners and operators can apply for a permit or trade allowances.
Commenters also argue that CAA section 111(h), which authorizes “design, equipment, work practice or operational standard[s]” (together, “design standards”) only when a source's emissions are not emitted through a conveyance or cannot be measured, makes clear that CAA section 111 standards of performance must be based on measures integrated into a source's own design or operations. We disagree. CAA section 111(h) concerns the relatively rare situation in which an emission standard, which entails a numerical limit on emissions,
Some commenters identify other provisions of CAA section 111 that, in their view, prove that CAA section 111 is limited to control measures that are integrated within the design or operations of the source. We do not find those arguments persuasive, for the reasons discussed in the supporting documents for this rule.
Commenters also argue, more generally, that Congress knew how to authorize control measures such as RE, as indicated by Congress's inclusion of those measures in Title IV (relating to acid rain), so the fact that Congress did not explicitly include these measures in the BSER provisions of CAA section 111(d)(1) and (a)(1) indicates that Congress did not intend that they be included as part of the BSER, and instead intended that the BSER be limited to measures integrated into the sources' design or operations. This argument misses the mark. The provisions of CAA section 111(d)(1) and (a)(1) do not explicitly include
c.
To the extent that it is not clear whether the phrase “system of emission reduction” may include the measures in building blocks 2 and 3, the EPA's interpretation of CAA section 111(d) and (a) is reasonable
Our interpretation that a “system of emission reduction” for the affected EGUs may include building blocks 2 and 3 is a reasonable construction of the statute for the reasons described above and in this section below.
(1)
(a)
Certain characteristics of the utility power sector are of central importance for understanding why the measures of building blocks 2 and 3 qualify as part of the system of emission reduction. As discussed above, electricity is highly substitutable and the utility power sector is highly integrated, so much so that it has been likened to a “complex machine.”
These characteristics of the sector have facilitated the overall objective of providing reliable electric service at least cost subject to a variety of constraints, including environmental constraints. Moreover, in each type of market, the sector has developed mechanisms, including the participation of institutional actors, to safeguard reliability and to assure least cost service.
Congress,
(b)
The fungibility of electricity, coupled with the integration of the utility power sector, means that, assuming that demand is held constant, adding electricity to the grid from one generator will result in the instantaneous reduction in generation from other generators. Similarly, reductions in generation from one generator lead to the instantaneous increase in generation from other generators. Thus, the operation of individual EGUs is integrated and coordinated with the operations of other EGUs and other sources of generation, as well as with electricity users. This allows for locational flexibility across the sector in meeting demand for electricity services. The institutions that coordinate planning and operations routinely use this flexibility to meet demand for electricity services economically while satisfying constraints, including environmental constraints. Because of these characteristics, EGU owner/operators have long conducted their business, including entering into commercial arrangements with third parties, based on the premise that the performance and operations of any of their facilities is substantially dependent on the performance and operation of other facilities, including ones they neither own nor operate. For example, when an EGU goes off-line to perform maintenance, its customer base is served by other EGUs that increase their generation. Similarly, if an EGU needs to assure that it can meet its obligations to supply a certain amount of generation, it may enter into arrangements to purchase that generation, if it needs to, from other EGUs.
Because of this structure, fossil fuel-fired EGUs can reduce their emissions by taking the actions in building blocks 2 and 3. Specifically, fossil fuel-fired EGUs may generate or cause the generation of increased amounts of lower- or zero-emitting electricity—through contractual arrangements, investment, or purchase—which will back out higher-emitting generation, and thereby lower emissions. In addition, fossil fuel-fired EGUs may reduce their generation, which, given the overall emission limits this rule requires, will have the effect of stimulating lower- or zero-emitting generation.
It should also be noted that CO
In light of these characteristics of the utility power sector, as well as the characteristics of CO
As discussed above, no such restriction on the measures that can be considered part of a “system of emission reduction” is required by the statutory language, and the legislative history demonstrates that Congress intended an interpretation of the phrase broad enough to encompass building blocks 2 and 3. The narrow interpretation advocated by some commenters would permit consideration only of potential CO
The unique characteristics of the sector described above require coordinated action in the fundamental, primary function of EGUs—and in meeting current pollution control requirements to the extent that EGUs operate in dispatch systems that apply variable costs in determining dispatch—and affected EGUs necessarily already plan and operate on a multi-unit basis. In doing so, they already make use of building blocks 2 and 3 to meet operational and environmental objectives in a cost-effective manner, as further described below. CO
(2)
The requirement that the “system of emission reduction” be “adequately demonstrated” suggests that we begin our review under CAA section 111(d)(1) and (a)(1) with the systems that sources are already implementing to reduce their emissions. As noted above, fossil fuel-fired EGUs have long implemented, and are continuing to implement, the measures in building blocks 2 and 3 for various purposes, including for the purpose of reducing CO
(3)
Some of the building block approaches to reducing emissions in the utility power sector were first tested around the time that Congress adopted the 1970 CAA Amendments.
(a)
It is logical that in determining whether the “system of emission reduction” that Congress established in CAA section 111(d)(1) and (a)(1) is broad enough to include the measures in building blocks 2 and 3 as the basis for establishing emission guidelines for fossil fuel-fired EGUs, an inquiry should be made into the tools that Congress relied on in other CAA provisions to reduce emissions from those same sources. The most useful CAA provision to examine for this purpose is Title IV, which includes a nationwide cap-and-trade program under which coal-fired power plants must have allowances for their SO
Title IV includes several signals that it is especially relevant for interpreting and implementing CAA section 111(d) for purposes of this rule. Title IV applies to most of the same sources that this rule applies to—existing coal-fired EGUs and other utility boilers, as well as NGCC units. In addition, Congress added Title IV in the 1990 CAA Amendments at the same time that Congress largely reinstated the 1970-vintage reading of section 111(a)(1) to adopt the currently applicable definition of a “standard of performance,” which is based on the “best system of emission reduction . . . adequately demonstrated.” Moreover, Congress linked Title IV and CAA section 111 in certain respects. Specifically, Congress conditioned the revisions to CAA section 111(a)(1),
For present purposes, the essential features of Title IV are that it regulates SO
(b)
Several provisions of Title IV make explicit Congress's reliance on some of the same measures as are in building blocks 2 and 3. Title IV begins with a statement of congressional “findings,” including the finding that “strategies and technologies for the control of precursors to acid deposition exist now that are economically feasible, and improved methods are expected to become increasingly available over the next decade.” CAA section 401(a)(4) (emphasis added). Title IV then identifies as its “purposes,” “to reduce the adverse effects of acid deposition through reductions in annual emissions of sulfur dioxide . . . and nitrogen oxides,” as well as “to encourage energy conservation, use of renewable and clean alternative technologies, and pollution prevention as a long-range strategy, consistent with the provisions of this subchapter, for reducing air pollution and other adverse impacts of energy production and use.” CAA section 401(b) (emphasis added).
By its terms, this statement of Title IV's purposes explicitly embraces the
In addition, Title IV includes other provisions expressly concerning RE. In CAA section 404(f) and (g), Congress set aside a special pool of allowances to encourage use of RE. In order to obtain a special allowance (which would authorize emissions from a coal-fired utility), an electric utility needed to pay for qualifying RE sources “directly or through purchase from another person.”
(c)
Numerous statements in the legislative history confirm that Congress based the Title IV requirements on the fact that affected EGUs could reduce their SO
For example, the Senate Committee Report
We believe that this provision of the bill will establish a balanced and workable approach that will provide certainty for utility companies that are considering conservation and renewables, while at the same time strengthening the environmental goals of this legislation.
(4)
The Title IV legislative history also makes clear that Congress viewed RE measures as a means to reduce CO
In enacting the 1990 CAA Amendments, Congress identified reductions in carbon dioxide emissions as an important co-benefit of the reductions in coal use and stressed that the RE measures would achieve those reductions. Senator Fowler, the author of the provision that established a RE technology reserve within the allowance system, noted that RE technologies, “can greatly reduce emissions of . . . global warming gases. That makes them a potent weapon against catastrophic climate change . . . .”
In addition, the 1990 CAA Amendments required EGUs covered by the monitoring requirements of the Title IV acid rain program to report their CO
(5)
Another indication that it is reasonable to interpret the CAA section 111(d)(1) and (a)(1) provisions for the BSER to include the measures in building blocks 2 and 3 is that the EPA and states have relied on these measures to reduce emissions in a number of other CAA actions.
For example, in 2005, the EPA promulgated a rule to control mercury emissions from fossil fuel-fired power plants under section 111(d): The Clean Air Mercury Rule (CAMR).
In 2011, the EPA promulgated the Cross State Air Pollution Rule (CSAPR),
With respect to RE, in 2004, the EPA provided guidance to states for adopting attainment SIPs under CAA section 110 that include RE measures.
(6)
The EPA has promulgated numerous actions that establish control requirements for affected sources on the basis of actions by other entities or actions other than measures integrated into the design or operations of the affected sources. This section summarizes some of those actions. First, virtually all pollution control requirements require the affected sources to depend in one way or another on other entities, such as control technology manufacturers. Second, the EPA has promulgated numerous regulatory actions that are based on trading of mass-based emission allowances or rate-based emission credits, in which many sources meet their emission limitation requirements by purchasing allowances or credits from other sources that reduce emissions.
(a)
To reiterate, commenters argue that the “system of emission reduction” must be limited to measures taken by the affected source itself because only those measures are under the control of the affected source, as opposed to third parties, and therefore only those measures can assure that the affected source will achieve its emission limits. But this argument is belied by the fact that for a wide range of pollution control measures—including many that are indisputably part of a “system of emission reduction”—affected sources are in fact dependent on third parties. For example, to implement any type of add-on pollution control equipment that is available only from a third-party manufacturer, the affected source is dependent upon that third party for developing and constructing the necessary controls, and for offering them for sale. Indeed, the affected sources may be dependent upon third parties to install (and in some cases to operate) the controls as well, and in fact, in the CAIR rule, the EPA established the compliance date based on the limited availability of the specialized workforce needed to install the controls needed by the affected EGUs.
In this rule, as noted, the affected EGUs may, in many cases, implement the measures in building blocks 2 and 3 directly, and, in other cases, implement those measures by engaging in market transactions with third parties that are as much within the affected EGUs' control as engaging in market transactions with the range of third parties involved in pollution control equipment. By the same token, the market transactions that the affected EGUs engage in with third parties to implement the measures in building blocks 2 and 3 are comparable to the market transactions that affected EGUs engage in as part of their normal course of business, which include, among many examples, transactions with RTOs/ISOs or balancing authorities, entities in organized markets.
(b)
Additional precedent that the “system of emission reduction” may include the measures in building blocks 2 and 3 and is not limited to measures that a source can integrate into its own design or operations, without being dependent on other entities, is found in the many rules that Congress has enacted or that the EPA has promulgated that allow EGUs and other sources to meet their emission limits by trading with other sources. In a trading rule, the EPA authorizes a source to meet its emission limit by purchasing mass-based emission allowances or rate-based emission credits generated from other sources, typically ones that implement controls that reduce their emissions to the point where they are able to sell allowances or credits. As a result, the availability of trading reduces overall costs to the industry by focusing the controls on the particular sources that have the least cost to implement controls. For present purposes, what is relevant is that in a trading program, some affected sources choose to meet their emission limits not by implementing emission controls integrated into their own design or operations, but rather by purchasing allowances or credits. These affected sources, therefore, are dependent on the actions of other entities, which are the ones that choose to meet their emission limits by implementing emission controls, which permits them to sell allowances or credits. They are dependent, however, in the same way that a source acquiring pollution control technology for the purposes of meeting a NSPS is dependent on a vendor of that technology to fulfill its contractual obligations. That is, the source operator purchasing a credit or an allowance is acquiring an equity in the technology or action applied to the credit-selling source for purposes of achieving a reduction in emissions occurring at the selling source. Trading programs have been commonplace under the CAA, particularly for EGUs, for decades. They include the acid rain trading program in Title IV of the CAA, the trading programs in the transport rules promulgated by the EPA under the “good neighbor provision” of CAA section 110(a)(2)(D)(i)(I), the Clean Air Mercury Rule, and the regional haze rules. In each of these actions, the Congress or the EPA recognized that some of the affected EGUs would implement controls or take other actions that would lower their emissions and thereby allow them to sell allowances to other EGUs, which were dependent on the purchase of those allowances to meet their obligations.
(c)
The EPA has promulgated NSPS for EGUs that include requirements based on the fact that an EGU may reduce its generation, and therefore its emissions, because the integration of the grid allows another EGU to increase generation and thereby avoid jeopardizing the supply of electricity. For example, in 1979, the EPA finalized new standards of performance to limit emissions of SO
Additionally, in 1982, the EPA recognized that utility turbines could meet a NO
(7)
Interpreting the term “system of emission reduction” broadly to include building blocks 2 and 3 (so that the “best system of emission reduction . . . adequately demonstrated” may include those measures as long as they meet all of the applicable requirements) is also consistent with the purposes of the CAA. Most importantly, these purposes include protecting public health and welfare by comprehensively addressing air pollution, and, particularly, protecting against urgent and severe threats. In addition, these purposes include promoting pollution prevention measures, as well as the advancement of technology that reduces air pollution.
(a)
The first provisions in the Clean Air Act set out the “Congressional findings and declaration of purpose.” CAA section 101. CAA section 101(a)(2) states the finding that “the growth in the amount and complexity of air pollution brought about by urbanization, industrial development, and the increasing use of motor vehicles, has resulted in mounting dangers to the public health and welfare.” CAA section 101(a)(3) states the finding that “air pollution prevention (that is, the reduction or elimination, through any measures, of the amount of pollutants produced or created at the source) and air pollution control at its source is the primary responsibility of States and local governments.” CAA section 101(a) states the finding that “Federal financial assistance and leadership is essential for the development of cooperative Federal, State, regional, and local programs to prevent and control air pollution.”
CAA section 101(b) next states “[t]he purposes” of the Clean Air Act. The first purpose is “to protect and enhance the
As just quoted, these provisions are explicit that the purpose of the CAA is “to protect and enhance the quality of the Nation's air resources so as to promote the public health and welfare and the productive capacity of its population.” Moreover, Congress designed the CAA to be “the comprehensive vehicle for protection of the Nation's health from air pollution”
At its core, Congress designed the CAA to address urgent and severe threats to public health and welfare. This purpose is evident throughout 1970 CAA Amendments, which authorized stringent remedies that were necessary to address those problems. By 1970, Congress viewed the air pollution problem, which had been worsening steadily as the nation continued to industrialize and as automobile travel dramatically increased after World War II,
Similarly, the 1977 and 1990 CAA Amendments were also designed to respond to new and/or pressing environmental issues. For example, in 1977 then-EPA Administrator Costle testified before Congress that the expected increase in coal use (in response to various energy crises, including the 1973-74 Arab Oil Embargo) “will make vigorous and effective control even more urgent.”
Climate change has become the nation's most important environmental problem. We are now at a critical juncture to take meaningful action to curb the growth in CO
Thus, interpreting the “system of emission reduction” provisions in CAA section 111(d)(1) and (a)(1) to allow the nation to meaningfully address the urgent and severe public health and welfare threats that climate change pose is consistent with what the CAA was designed to do.
(b)
Interpreting “system of emission reduction” to include building blocks 2 and 3 is also consistent with the CAA's purpose to encourage pollution prevention. CAA section 101(c) states that “[a] primary goal of [the CAA] is to encourage or otherwise promote reasonable federal, state, and local governmental actions, consistent with the provisions of this chapter, for pollution prevention.” Indeed, in the U.S. Code, in which the CAA is codified as chapter 85, the CAA is entitled, “Air Pollution Prevention and Control.”
The measures in building blocks 2 and 3 qualify as “pollution prevention” measures because they are “any measures” that “reduc[e] or eliminate[e] . . . the amount of pollutants produced or created at the [fossil fuel-fired affected] source[s].” Thus, consistent with the CAA's primary goals, it is therefore reasonable to interpret a “system of emission reduction,” as including the pollution prevention measures in building blocks 2 and 3.
(c)
This final rule is also consistent with CAA section 111's purpose of promoting the advancement of pollution control technology based on the expectation that American industry will be able to develop innovative solutions to the environmental problems.
The legislative history and case law of CAA section 111 identify three different ways that Congress designed CAA section 111 to authorize standards of performance that promote technological improvement: (i) The development of technology that may be treated as the “best system of emission reduction . . . adequately demonstrated;” under CAA section 111(a)(1);
This final rule is also consistent with Congress's overall view that the CAA Amendments as a whole were designed to promote technological innovation. In enacting the CAA, Congress articulated its expectation that American industry would be creative and come up with innovative solutions to the urgent and severe problem of air pollution. This is manifest in the well-recognized technology-forcing nature of the CAA, and was expressed in numerous, sometimes ringing, statements in the legislative history about the belief that American industry will be able to develop the needed technology. For example, in the 1970 floor debates, Congress recalled that the nation had put a man on the moon a year before and had won World War II a quarter century earlier, and attributed much of the credit for those singular achievements to American industry and its ability to be productive and innovative. Congress expressed confidence that American industry
(d)
Commenters have stated that the proposed rule “would transform CAA section 111 into something untethered to its statutory language and unrecognizable to the Congress that created it.”
(8)
Although the BSER provisions are sufficiently broad to include, for affected EGUs, the measures in building blocks 2 and 3, they also incorporate significant constraints on the types of measures that may be included in the BSER. We discuss those constraints in this section. These constaints explain why we are not including building block 4 in the BSER. In addition, these constraints explain why our reliance on building blocks 2 and 3 will have limited precedential effect for other rulemakings, and serve as our basis for responding to commenters who expressed concern that reliance on building blocks 2 and 3 would set a precedent for the EPA to rely on similar measures in promulgating future air pollution controls for other sectors.
As discussed above, the emission limits in the CAA section 111(d) emission guidelines that this rule promulgates are based on the EPA's determination, for the affected EGUs, of the “system of emission reduction” that is the “best,” taking into account “cost” and other factors, and that is “adequately demonstrated.” Those components include certain interpretations and applications and provide constraints on the types of measures or controls that the EPA may determine to include in the BSER.
(a)
The first constraint is that the BSER must assure emission reductions from the affected sources. Under section 111(d)(1), the states must submit state plans that “establish[] standards of performance for any existing source,” and, under section 111(a)(1) and the EPA's implementing regulations, those standards are informed by the EPA's determination of the best system of emission reduction adequately demonstrated. Because the emission standards must apply to the affected sources, actions taken by affected sources that do not result in emission reductions from the affected sources—for example, offsets (
(b)
The second constraint is that because the affected EGUs must be able to achieve their emission performance rates through the application of the BSER, the BSER must be controls or measures that the EGUs themselves can implement. Moreover, as noted, the D.C. Circuit has established criteria for achievability in the section 111(b) case law;
(c)
The third constraint is that the system of emission reduction that the EPA determines to be the best must be “adequately demonstrated.” To qualify as the BSER, controls and measures must align with the nature of the regulated industry and the nature of the pollutant so that implementation of those controls or measures will result in emission reductions from the industry and allow the sources to achieve their emission performance standards. The history of the effectiveness of the controls or other measures, or other indications of their effectiveness, are important in determining whether they are adequately demonstrated.
More specifically, the application of building blocks 2 and 3 to affected EGUs has a number of unique characteristics. Building blocks 2 and 3 entail the production of the same amount of the same product—electricity, a fungible product that can be produced using a variety of highly substitutable generation processes—through the cleaner (that is, less CO
The physical properties of electricity and the highly integrated nature of the electricity system allow the use of these cleaner processes to generate the same amount of electricity. In addition, the electricity sector is primarily domestic—little electricity is exported outside the U.S.—and there is low capacity for storage. In addition, the electricity sector is highly regulated, planned, and coordinated. As a result, holding demand constant, an increase in one type of generation will result in a decrease in another type of generation. Moreover, the higher-emitting generators, which are fossil fuel-fired, have higher variable costs than renewable generators, so that increased renewable generation will generally back out fossil fuel-fired generation.
Because of these characteristics, the electricity sector has a long and well-established history of substituting one type of generation for another. This has occurred for a wide variety of reasons, many of which are directly related to the system's primary purposes and functions, as well as for environmental reasons. As a result, at present, there is a well-established network of business and operational relationships and past practices that supports building blocks 2 and 3. As noted elsewhere, a large segment of steam generators already have business relationships with existing NGCC units, and a large segment of all fossil fuel-fired EGUs already own, co-own, or have invested in RE.
Many of these characteristics are unique to the utility power sector. Moreover, this complex of characteristics, ranging from the physical properties of electricity and the integrated nature of the grid to the institutional mechanisms that assure reliability and the existing practices and business relationships in the industry, combine to facilitate the implementation of building blocks 2 and 3 in a uniquely efficient manner. This supports basing the emission limits on the ability of owners and operators of fossil fuel-fired EGUs to replace their generation with cleaner generation in other locations, sometimes owned by other entities.
As noted above, commenters offered hypothetical examples to illustrate their concerns over precedential effects. Most of their concerns focused on building block 4, and most of their hypothetical examples concerned reductions in demand for various types of products. We address these concerns in the response to comments document, but we note here that, in any event, these concerns are mooted because we are not finalizing building block 4. Some commenters offered hypothetical examples for building blocks 2 and 3 as well. For example, some commenters asserted that the EPA could “develop standards of performance for tailpipe emissions from motor vehicles” by “requiring car owners to shift some of their travel to buses,” which the commenters considered analogous to building block 2; or by “requiring there to be more electric vehicle purchases,” which the commenters considered analogous to building block 3.
Commenters' concerns over precedential impact cannot be taken to mean that the building blocks should not be considered to meet the requirements of the BSER or that the affected EGUs cannot be considered to meet the emission limits by implementing those measures. Moreover, because many of these individual characteristics, and their inherent complexity, are unique to the utility power sector, building blocks 2 and 3 as applied to fossil fuel-fired EGUs will have a limited precedent for other industries and other types of rulemakings. For example, the commenter's hypothetical examples noted above are inapposite for several reasons. The hypotheticals appear to be premised on government action mandating actions not implementable by emitting sources (
(d)
The fourth constraint, or set of constraints, is that the system of emission reduction must be the “best,” “taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements.” As noted, in light of the D.C. Circuit case law, the EPA has considered cost and energy factors on both an individual source basis and on the basis of the nationwide electricity sector. In determining what is “best,” the EPA has broad discretion to balance the enumerated factors.
The great majority of our regulations under section 111 have been 111(b) regulations for new sources. As discussed in the Legal Memorandum and briefly below, the BSER identified under section 111(b) is designed to assure that affected sources are well controlled at the time of construction, and that approach is consistent with the design expressed in the legislative history for the 1970 CAA Amendments that enacted the provision.
Traditionally, CAA section 111 standards have been rate-based, allowing as much overall production of a particular good as is desired, provided that it is produced through an appropriately clean (or low-emitting) process. CAA section 111 performance standards have primarily targeted the means of production in an industry and not consumers' demand for the product. Thus, the focus for the BSER has been on how to most cleanly produce a good, not on limiting how much of the good can be produced.
One example of the focus under section 111 on clean production, not limitation of product is provided by the revised new source performance standards for electric utility steam generating units that we promulgated in 1979 following the 1977 CAA Amendments to limit emissions of SO
Similarly, in a series of rulemakings regulating air pollutants from EGUs under several provisions of the CAA, we have focused our efforts on assuring that electricity is generated through cleaner or lower-emitting processes, and we have not sought to limit the aggregate amount of electricity that is generated. We describe those rules in section II, elsewhere in this section V.B.3., and in the Legal Memorandum.
For example, as discussed in the Legal Memorandum, in the three transport rules promulgated under CAA section 110(a)(2)(D)(i)(I)—the NO
While these and other rulemakings for fossil fuel-fired EGUs took different approaches towards lower-emitting generation and renewable generation, they all were based on control measures that reduced emissions without reducing aggregate levels of electricity generation. It should be noted that even though some of those rules established overall emission limits in the form of budgets implemented through a cap-and-trade program, the EPA recognized that the fossil fuel-fired EGUs that were subject to the rules could comply by shifting generation to lower-emitting EGUs, including relying on RE. In this manner, the rules limited emissions but on the basis that the industry could implement lower-emitting processes, and not based on reductions in overall generation.
We are applying the same approach to this rulemaking. Our basis for this rulemaking is that affected EGUs can implement a system of emission reduction that will reduce the amount of their emissions without reducing overall electricity generation. This approach takes into account costs by minimizing economic disruption as well as the nation's energy requirements by avoiding the need for environmental-based reductions in the aggregate amount of electricity available to the consumer, commercial, and industrial sectors.
This approach is a reasonable exercise of the EPA's discretion under section 111, consistent with the U.S. Supreme Court's statements in its 2011 decision,
Similarly, the D.C. Circuit, in a 1981 decision upholding the EPA's section 111(b) standards for air pollutants from fossil fuel-fired EGUs, stated that section 111 regulations concerning the electric power sector “demand a careful weighing of cost, environmental, and energy considerations.”
Our interpretation that CAA section 111 targets supply-side activities that allow continued production of a product through use of a cleaner process, rather than targeting consumer-oriented behavior, also furthers Congress' intent of promoting cleaner production measures “to protect and enhance the quality of the Nation's air resources so as to promote the public health and welfare and the productive capacity of its population.”
In this rule, we are applying that same approach in interpreting the BSER provisions of section 111. That is, we are basing the regulatory requirements on measures the affected EGUs can implement to assure that electricity is generated with lower emissions, taking into account the integrated nature of the industry and current industry practices. Building blocks 1, 2 and 3 fall squarely within this paradigm; they do not require reductions in the total amount of electricity produced.
We recognize that commenters have raised extensive legal concerns about building block 4. We recognize that building block 4 is different from building blocks 1, 2, and 3 and the pollution control measures that we have considered under CAA section 111. Accordingly, under our interpretation of section 111, informed by our past practice and current policy, today's final action excludes building block 4 from the BSER. Building block 4 is outside our paradigm for section 111 as it targets
Although numerous commenters urged us to include demand-side EE measures as part of the BSER, as we had proposed to do, we conclude that we cannot do so under our historical practice, current policy, and current approach to interpreting section 111 as well as our historical practice in regulating the electricity sector under other CAA provisions. While building blocks 2 and 3 are rooted in our past practice and policy, building block 4 is not and would require a change (which we are not making) in our interpretation and implementation and application of CAA section 111.
Excluding demand-side EE measures from the BSER has the benefit of allaying legal and other concerns raised by commenters, including concerns that individuals could be “swept into” the regulatory process by imposing requirements on “every household in the land.”
By the same token, we are not finalizing reduced generation of electricity overall as the BSER. Instead, components of the BSER focus on shifting generation to lower- or zero-emitting processes for producing electricity.
(e)
For new sources, practical and policy concerns support the interpretation of basing the BSER on controls that new sources can install at the time of construction, so that they will be well-controlled throughout their long useful lives. This approach is consistent with the legislative history. We discuss this at greater length in the Legal Memorandum.
In this section, we discuss the relationship between an affected EGU's implementation of the measures in building blocks 2 and 3 and that affected EGU's own generation and emissions. As discussed above, an affected EGU subject to a CAA section 111(d) state plan that imposes an emission rate-based standard may achieve that standard in part by implementing the measures in building block 2 (for a steam generator) and building block 3 (for a steam generator or combustion turbine). That is, an affected EGU may invest in low- or zero-emitting generation and may apply credits from that generation against its emission rate. Those credits reduce the affected EGU's emission rate and thereby help it to achieve its emission limit.
In addition, the additional low- or zero-emitting generation that results from the affected EGU's investment will generally displace higher-emitting generation. This is because, as described above, higher-emitting generation generally has higher variable costs, reflecting its fuel costs, than, at least, zero-emitting generation. Displacement of higher-emitting generation will lower overall CO
If an affected EGU implements building block 2 or 3 by reducing its own generation, it will reduce its own emissions. However, the affected EGU may also or alternatively choose to implement building block 2 or 3 by investing in lower- or zero-emitting generation that does not, in and of itself, reduce the amount of its own generation or emissions. Even so, implementation of building blocks 2 and 3 will reduce CO
This outcome is, however, consistent with the requirements of CAA section 111(d)(1) and (a)(1). To reiterate, CAA section 111(d)(1) requires that “any existing source” have a “standard of performance,” defined under CAA section 111(a)(1) as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction . . . adequately demonstrated [BSER] . . . .” These provisions require by their terms that “any existing source” must have a “standard of performance,” but nothing in these provisions requires a particular amount—or, for that matter, any amount—of emission reductions from each and every existing source. That the “standard of performance” is defined on the basis of the “degree of emission limitation achievable through the application of the [BSER]” does not mean that each affected EGU must achieve some amount of emission reduction, for the following reasons.
The cornerstone of the definition of the term “standard of performance” is the BSER. In determining the BSER, the EPA must consider the amount of emission reduction that the system may achieve, and must consider the ability of the affected EGUs to achieve the emission limits that result from the application of the BSER. The EPA is authorized to include in the BSER, for this source category, the measures in building blocks 2 and 3 because, when applied to the source category, these measures result in emission standards that may be structured to ensure overall emission reductions from the source category and remain achievable by the affected EGUs. This remains so regardless of whether the “degree of emission limitation achievable through the application of the [BSER]” by any particular source results in actual emission reductions from that source.
The application of the building blocks has an impact that is similar to that of an emissions trading program, under which, overall, the affected sources reduce emissions, but any particular source does not need to reduce its emissions and, in fact, may increase its emissions, as long as it purchases sufficient credits or allowances from other sources. In fact, we expect that many states will carry out their obligations under this rule by imposing standards of performance that incorporate trading or other multi-entity generation-replacement strategies. Indeed, any emission rate-based standard may not necessarily result in emission reductions from any particular affected source (or even all of the affected sources in the category) as a result of the ability of the particular source (or even all of them) to increase its production and, therefore, its emissions, even while maintaining the required emission rate.
In the proposed rulemaking, we described the BSER as the measures included in building block 1 as well the set of measures included in building blocks 2, 3 and 4 or, in the alternative, reduced generation or utilization by the affected EGUs in the amount of building blocks 2, 3 and 4. In this final rule, based on the comments and further evaluation, we are refining our approach to the BSER. Specifically, we are determining the BSER as the combination of measures included in building blocks 1, 2, and 3.Building blocks 2 and 3 entail substitution of lower-emitting generation for higher-emitting generation, which ensures that aggregate production levels can continue to meet demand even where an individual affected EGU decreases its
a.
b.
Reduced generation in the amounts contemplated in this rule, as undertaken by individual sources to achieve their emission limits, reduces emissions from the affected sources, but because of the integrated and interconnected nature of the power sector, can be accommodated without significant cost or disruption. The electric transmission grid interconnects the nation's generation resources over large regions. Electric system operators coordinate, control, and monitor the electric transmission grid to ensure cost-effective and reliable delivery of power. These system operators continuously balance electricity supply and demand, ensuring that needed generation and/or demand resources are available to meet electricity demand. Diverse resources generate electricity that is transmitted and distributed through a complex system of interconnected components to end-use consumers.
The electricity system was designed to meet these core functions. The three components of the electricity supply system—generation, transmission and distribution—coordinate to deliver electricity from the point of generation to the point of consumption. This interconnectedness is a fundamental aspect of the nation's electricity system, requiring a complicated integration of all components of the system to balance supply and demand and a federal, state and local regulatory network to oversee the physically interconnected network. Electricity from a diverse set of generation resources such as natural gas, nuclear, coal and renewables is distributed over high-voltage transmission lines. The system is planned and operated to ensure that there are adequate resources to meet electricity demand plus additional available capacity over and above the capacity needed to meet normal peak demand levels. System operators have a number of resources potentially available to meet electricity demand, including electricity generated by electric generation units of various types as well as demand-side resources. Importantly, if generation is reduced from one generator, safeguards are in place to ensure that adequate supply is still available to meet demand. We describe these safeguards in the background section of this preamble.
Both Congress and the EPA have recognized reduced generation as one of the measures that fossil fuel-fired EGUs may implement to reduce their emissions of air pollutants and thereby achieve emission limits. Congress, in enacting the allowance requirements in CAA Title IV, under which fossil fuel-fired EGUs must hold an allowance for each ton of SO
The EPA has also recognized in several rulemakings limiting emissions from fossil fuel-fired EGUs that reduced generation is one of the methods of emission reduction that an EGU was expected to rely on to achieve its emission limitations. Examples include rulemakings to impose requirements that sources implement BART to reduce their emissions of air pollutants that cause or contribute to visibility impairment. As explained earlier, for certain older stationary sources that cause or contribute to visibility impairment, including fossil fuel-fired EGUs, states must determine BART on the basis of five statutory factors, such as costs and energy and non-air quality impacts.
There have been numerous other instances in which fossil fuel-fired EGUs have reduced their individual generation, or placed limits on their generation, in order to achieve, or obviate, emission standards. In fact, there are numerous examples of EGUs that take restrictions on hours of operation in their permits for the purpose of avoiding CAA obligations, including avoiding triggering the requirements of the Prevention of Significant Deterioration (PSD), Nonattainment New Source Review (NNSR), or Title V programs (including Title V fees), and avoiding triggering HAP requirements. Such restrictions may also be taken to limit emissions of pollutants, such as limiting emissions of criteria pollutants for attainment purposes.
More specifically, EPA's regulations for a number of air programs expressly recognize that certain sources may take enforceable limits on hours of operation in order to avoid triggering CAA obligations that would otherwise apply to the source. Stationary sources that emit or have the
As one of many examples of a fossil-fuel fired EGU taking restrictions on hours of operation for the purpose of avoiding CAA obligations, Manitowoc Public Utilities in Wisconsin obtained a Title V renewal permit that limited the operating hours of the single simple-cycle combustion turbine to not more than 194 hours per month, averaged over any consecutive 12 month period, as part of limiting its potential to emit for volatile organic compounds below the Title V threshold of 100 tpy, and carbon monoxide, NO
There are several ways that an affected EGU may implement reduced generation. For example, an EGU may accept a permit requirement that specifically limits its operating hours. In addition, an EGU may treat the cost of its generation as including an additional amount associated with environmental impacts, which requires it to raise its bid price, so that the EGU is dispatched less.
c.
The amounts of increased existing NGCC generation and new renewables, in the amounts reflected in building blocks 2 and 3, can be substituted for generation at affected EGUs at reasonable cost. The NGCC capacity necessary to accomplish the levels of generation reduction proposed for building block 2 is already in operation or under construction. Moreover, it is reasonable to expect that the incremental resources reflected in building block 3 will develop at the levels requisite to ensure an adequate and reliable supply of electricity at the same time that affected EGUs may
Reduced generation by affected EGUs, in the amounts that affected EGUs may rely on to implement the selected building blocks, will not have adverse effects on the utility power sector and will not reduce overall electricity generation. In light of the emission limits of this rule, because of the availability of the measures in building blocks 2 and 3, and because the grid is interconnected and the electricity system is highly planned, reductions in generation by fossil fuel-fired EGUs in the amount contemplated if they were to implement the building blocks, and occurring over the lengthy time frames provided under this rule, will result in replacement generation that generally is lower- or zero-emitting. Mechanisms are in place in both regulated and deregulated electricity markets to assure that substitute generation will become available and/or steps to reduce demand will be taken to compensate for reduced generation by affected EGUs. As a result, reduced generation will not give rise to reliability concerns or have other adverse effects on the utility power sector and are of reasonable cost for the affected source category and the nationwide electricity system.
d.
A commenter stated that “an interpretation of [`system of emission reduction'] that relies primarily on reduced utilization has no clear limiting principle.”
As discussed, in this final rule, we are identifying the BSER as the combination of the three building blocks. Building blocks 2 and 3 entail substitution of lower- or zero-emitting generation for higher-emitting generation, and one component of that substitution is reduced generation, which is limited in several respects discussed below. Accordingly, our identification of the BSER in this final rule does not “rel[y] primarily” on reduced utilization in and of itself (and therefore reduced generation of the product overall, electricity) as the BSER. Rather, the BSER is, in addition to building block 1, the substitution of lower- or zero-emitting generation for higher emitting generation, and reduced utilization may be a way to implement that substitution and is one of numerous methods that affected EGUs may employ to achieve or help achieve the emission limits established by these emission guidelines.
Moreover, reduced generation, as applied to affected EGUs in this rule, is limited in a number of respects. The amount of reduced generation is the amount of replacement generation that is lower- or zero-emitting, that is of reasonable cost, that can be generated without jeopardizing reliability, and that meets the other requirements for the BSER. As discussed, that amount is the amount of generation in building blocks 2 and 3.
Finally, as discussed, the integrated nature of the electricity system, coupled with the high substitutability of electricity, allows EGUs to reduce their generation without adversely affecting the availability of their product. Those characteristics facilitate replacement of generation that has been reduced, and for that reason, EGUs have a long history of reducing their generation and either replacing it directly or having it replaced through the operation of the interconnected electricity system through measures similar to those in building blocks 2 and 3. Thus, an EGU can either directly replace its generation, or simply reduce its generation, and in the latter case, the integrated grid, combined with the high degree of planning and various reliability safeguards, will result in entities providing replacement generation. This means that consumers receive exactly the same amount of the same product, electricity, after the reduced generation that they received before it. No other industry is both physically interconnected in this manner and manufactures such a highly substitutable product; as a result, the use of reduced generation is not easily transferrable to another industry.
In this section, we respond to adverse comments that the EPA is overreaching in this rulemaking by attempting to direct the energy sector. These commenters construed the proposed rulemaking as the EPA proposing to mandate the implementation of the measures in the building blocks,
In this rule, the EPA is following the same approach that it uses in any rulemaking under CAA section 111(d), which is designed to regulate the air pollutants from the source category at issue. First, the EPA identifies the BSER to reduce harmful air pollution. Second, based on the BSER, the EPA promulgates emission guidelines, which generally take the form of emission rates applicable to the affected sources. In this case, the EPA is promulgating a uniform CO
Thus, the EPA is not requiring that the affected EGUs take any particular action, such as implementation of the building blocks. Rather, as just explained, the EPA is regulating the affected EGUs' emissions by requiring that the state submit state plans that achieve specified emission performance levels. The states may choose from a wide range of emission limits to impose on their sources, and the sources may choose from a wide range of compliance options to achieve their emission limits. Those options include various means of implementing the building blocks as well as numerous other compliance options, ranging from—depending in part on whether the state imposes a rate-based or mass-based emission limit—implementation of demand-side EE measures to natural gas co-firing.
As some indication of the diverse set of actions we expect to comply with the requirements of this rule, we note that demand-side EE programs, in particular, are expected to be a significant compliance method, in light of their low costs. In addition, the National Association of Clean Air Agencies (NACAA) has issued a report that provides a detailed discussion of 25 approaches to CO
As a practical matter, we expect that for some affected EGUs, implementation of the building blocks will be the most attractive option for compliance. This does not mean, contrary to the adverse comments noted above, that this rule constitutes a redesign of the energy sector. As discussed above, the building blocks meet the criteria to be part of the best system of emission reduction . . . adequately demonstrated. The fact that some sources will implement the building blocks and that this may result in changes in the electricity sector does not mean that the building blocks cannot be considered the BSER under CAA section 111(d).
In this rule, as with all CAA section 111(d) rules, the EPA is not directly regulating any entities. Moreover, the EPA is not finalizing the proposed portfolio approach. Accordingly, the EPA is neither requiring nor authorizing the states to regulate non-affected EGUs in their CAA section 111(d) plans.
Moreover, contrary to adverse comments, this rule does not require the states to adopt a particular type of energy policy or implement particulate types of energy measures. Under this rule, a state may comply with its obligations by adopting the emission standards approach to its state plan and imposing rate-based or mass-based emission standards on its affected EGUs. In this manner, this rule is consistent with prior section 111(d) rulemaking actions, in which the states have complied by promulgating one or both of those types of standards of performance. In this rulemaking, as an alternative, the state may adopt the state measures approach, under which the state could, if it wishes, adopt particular types of energy measures that would lead to reductions in emissions from its EGUs. But again, this rule does not require the state to implement a
It is certainly reasonable to expect that compliance with these air pollution controls will have costs, and those costs will affect the electricity sector by discouraging generation of fossil fuel-fired electricity and encouraging less costly alternative means of generating electricity or reducing demand. But for affected EGUs, air pollution controls necessarily entail costs that affect the electricity sector and, in fact, the entire nation, regardless of what BSER the EPA identifies as the basis for the controls. For example, had some type of add-on control such as CCS been identified as the BSER for coal-fired EGUs, sources that complied by installing that control would incur higher costs. As a result, generation from coal-fired EGUs would be expected to decrease and be replaced at least in part by generation from existing NGCC units and new renewables because those forms of generation would see their competitive positions improved.
This basic fact that EPA regulation of air pollutants from affected EGUs invariably affects the utility sector is well-recognized and in no way indicates that such regulation exceed the EPA's authority. In revising CAA section 111 in the 1977 CAA Amendments, Congress explicitly acknowledged that the EPA's rules under CAA section 111 for EGUs would significantly impact the energy sector.
[T]he Reports from both Houses on the Senate and House bills illustrate very clearly that Congress itself was using a long-term lens with a broad focus on future costs, environmental and energy effects of different technological systems when it discussed section 111. [Citing S. Rep. No. 95-127, 95th Cong., 1st Sess. (1977), 3 Legis. Hist. 1371; H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 188 (1977), 4 Legis. Hist. 2465.]
The appropriate amount of regulation in any particular greenhouse gas-producing sector cannot be prescribed in a vacuum: As with other questions of national or international policy, informed assessment of competing interests is required. Along with the environmental benefit potentially achievable, our Nation's energy needs and the possibility of economic disruption must weigh in the balance.
The [CAA] entrusts such complex balancing to EPA in the first instance, in combination with state regulators. Each “standard of performance” EPA sets must “tak[e] into account the cost of achieving [emissions] reduction and any nonair quality health and environmental impact and energy requirements.” § 7411(a)(1), (b)(1)(B), (d)(1); see also 40 CFR 60.24(f) (EPA may permit state plans to deviate from generally applicable emissions standards upon demonstration that costs are “[u]n-reasonable”). EPA may “distinguish among classes, types, and sizes” of stationary sources in apportioning responsibility for emissions reductions. § 7411(b)(2), (d); see also 40 CFR 60.22(b)(5). And the agency may waive compliance with emission limits to permit a facility to test drive an “innovative technological system” that has “not [yet] been adequately demonstrated.” § 7411(j)(1)(A). The Act envisions extensive cooperation between federal and state authorities, see § 7401(a), (b), generally permitting each state to take the first cut at determining how best to achieve EPA emissions standards within its domain, see § 7411(c)(1), (d)(1)-(2).
It is altogether fitting that Congress designated an expert agency, here, EPA, as best suited to serve as primary regulator of greenhouse gas emissions. The expert agency is surely better equipped to do the job than individual district judges issuing ad hoc, case-by-case injunctions.
Similarly, the D.C. Circuit, in its 1981 decision upholding the EPA's rules to reduce SO
[S]ection 111 most reasonably seems to require that EPA identify the emission levels that are “achievable” with “adequately demonstrated technology.” After EPA makes this determination, it must exercise its discretion to choose an achievable emission level which represents the best balance of economic, environmental, and energy considerations. It follows that to exercise this discretion EPA must examine the effects of technology on the grand scale in order to decide which level of control is best. . . . The standard is, after all, a national standard with long-term effects.
The D.C. Circuit added: “Regulations such as those involved here demand a careful weighing of cost, environmental, and energy considerations. They also have broad implications for national economic policy.”
Consider for a moment the chain of collective decisions and their effects just in the case of electric utilities. Petroleum imports can be conserved by switching from oil-fired to coal-fired generation. But barring other measures, burning high-sulfur Eastern coal substantially increases pollution. Sulfur can be “scrubbed” from coal smoke in the stack, but at a heavy cost, with devices that turn out huge volumes of sulfur wastes that must be disposed of and about whose reliability there is some question. Intermittent control techniques (installing high smokestacks and switching off burners when meteorological conditions are adverse) can, at lower cost, reduce local concentrations of sulfur oxides in the air, but cannot cope with the growing problem of sulfates and widespread acid rainfall. Use of low-sulfur Western coal would avoid many of these problems, but this coal is obtained by strip mining. Strip-mining reclamation is possible, but substantially hindered in large areas of the West by lack of rainfall. Moreover, in some coal-rich areas the coal beds form the underground aquifer and their removal could wreck adjacent farming or ranching economies. Large coal-burning plants might be located in remote areas far from highly populated urban centers in order to minimize the human effects of pollution. But such areas are among the few left that are unspoiled by pollution and both environmentalists and the residents (relatively few in number compared with those in metropolitan localities but large among the voting population in the particular states) strongly object to this policy.
As noted above, in this rule, to control CO
We expect that many sources will choose to comply with their emission limits through the measures in building blocks 2 and 3, but contrary to the assertions of some commenters, this will not result in unprecedented and fundamental alterations to the energy sector. As discussed above, Congress relied on the same measures as those the EPA is including in building blocks 2 and 3 as essential parts of the basis for the Title IV emission limits for fossil fuel-fired EGUs, and the EPA did the same for the emission limits in various rules for those same sources.
In addition, reliance on the measures in building blocks 2 and 3 is fully consistent with the recent changes and current trends in electricity generation, and as a result, would by no means entail fundamental redirection of the energy sector. As indicated in the RIA for this rule, we expect that the main impact of this rule on the nation's mix of generation will be to reduce coal-fired generation, but in an amount and by a rate that is consistent with recent historical declines in coal-fired generation. Specifically, from approximately 2005 to 2014, coal-fired generation declined at a rate that was greater than the rate of reduced coal-fired generation that we expect to result from this rulemaking from 2015 to 2030. In addition, under this rule, the trends for all other types of generation, including natural gas-fired generation, nuclear generation, and renewable generation, will remain generally consistent with what their trends would be in the absence of this rule. In addition, this rule is expected to result in increases in demand-side EE.
In addition, contrary to claims of some commenters, in this rule, the EPA is not attempting to expand its authorities by attempting to expand the jurisdiction of the CAA to previously unregulated sectors of the economy, in contravention of the
Commenters also objected that the proposed CAA section 111(d) standards are more stringent than the standards for new, modified or reconstructed sources, and they assert that setting CAA section 111(d) standards that are more stringent than CAA section 111(b) standards would be illogical, contrary to precedent, contrary to the intent of the remaining useful life exception, and arbitrary and capricious.
Most importantly, the two sets of rules become applicable at different points in time and have significantly different compliance periods. The CAA section 111(b) rule becomes applicable for new, modified and reconstructed sources immediately upon construction, modification, or reconstruction and, in fact, by operation of CAA section 111(e) and (a)(2), new, modified, or reconstructed sources that commenced construction prior to the effective date of the CAA section 111(b) rule must also be in compliance upon the effective date of the rule. In contrast, the requirements under the CAA section 111(d) rule do not become applicable to existing affected EGUs until seven years after promulgation of the rule, when the interim compliance period begins in 2022, and the final compliance period does not begin until 2030. Moreover, the compliance period for the interim requirements is eight years. This later applicability date and longer compliance period for existing sources accommodates a requirement that, on average, those sources have a lower nominal emission limit than the standards for new or modified sources, which those latter sources must comply with immediately.
In addition, the timetables for compliance with the CAA section 111(b) and 111(d) rules should be considered in light of the 8-year review schedule required for CAA section 111(b) rules under CAA section 111(b)(1)(B). Under CAA section 111(b)(1)(B), the EPA is required to “review and, if appropriate, revise” the CAA section 111(b) standards “at least every 8 years.” This provision obligates the EPA to review the CAA section 111(b) rule for CO
Specifically, as noted above, the CAA section 111(b) standards apply to new, modified and reconstructed sources beginning in 2015, while the CAA section 111(d) rule does not take effect until 2022, which happens to fall on the cusp of the 8-year review for the CAA section 111(b) standards.
Even after the section 111(d) rule takes effect in 2022, the flexibility that this rule offers the states has important implications for its stringency and for any comparison to the CAA section 111(b) rule. Although the requirements for the CAA section 111(d) rule begin in 2022, they are phased in, in a flexible manner, over the 2022-2030 period. That is, states are required to meet interim goals for the 2022-2029 period by 2029, and the final goals by 2030, but states are not required to impose requirements on their sources that take
Therefore, while the CAA section 111(b) standards apply to new, modified, and reconstructed sources beginning in 2015, the CAA section 111(d) standards may not apply to existing sources until 2023. As a result, by 2023—the year that the CAA section 111(b) standards are required to be reviewed for possible revision—affected EGUs subject to the CAA section 111(d) standards may remain uncontrolled. Under those circumstances, the CAA section 111(d) rule cannot be said to be more stringent than the CAA section 111(b) rule.
Another reason why the section 111(d) rule cannot be said to be more stringent than the section 111(b) rule is that for any individual source, the section 111(d) rule is applied more flexibly and includes more flexible means of compliance. Whereas the CAA section 111(b) rule entails an emission rate that each affected EGU must meet on a 12-month (rolling) basis, the CAA section 111(d) is more flexible. For example, states may adopt the state measures approach and refrain from imposing any requirements on their affected EGUs. In addition, under the CAA section 111(d) rule, sources have more flexible means of compliance. For an emission standards approach, depending on the form of the state requirements (mass-based or rate-based), the state may be expected to authorize trading of mass-based emission allowances or rate-based emission credits, and in addition, the purchase of ERCs. These flexibilities are not included in the CAA section 111(b) rule, rather, as noted, each new, modified, and reconstructed EGU must individually meet its emission standard on a 12-month (rolling) basis. The EPA has frequently required that sources meet a more stringent nominal limit when they are allowed compliance flexibility, particularly, the opportunity to trade.
There are other reasons why the CAA section 111(d) rule cannot be said to be more stringent. With respect to the CAA section 111(d) and 111(b) rules for existing and new NGCC units, we note the following: As explained in the CAA section 111(b) preamble, the standard for new NGCC units is designed to accommodate a wide range of unit types, including small units and rapid-start units, which are a small part of the expected new NGCC generation capacity. As such, the CAA section 111(b) standard (1,000 lb CO
Moreover, even if commenters were correct that the CAA section 111(d) requirements for existing sources are more stringent than the CAA section 111(b) requirements for new sources, that would not, by itself, call into question the reasonableness of either standard. The stringency of the requirements for each source subcategory is, of course, a direct function of the BSER identified for that source subcategory. In this rulemaking, we explain the basis for the BSER for existing sources, and why we do not include certain measures, such as CCS; and in the CAA section 111(b) rulemaking, we explain the basis for the
The first category of approaches to reducing CO
An EGU's heat rate is the amount of fuel energy input needed (Btu, higher heating value basis) to produce 1 kWh of net electrical energy output.
As discussed above in section V.A and in the June 2014 proposal,
We conducted several analyses to assess the potential for heat rate improvements from the coal-fired EGU fleet. As in the proposal, we employed a unit-specific approach that compared each EGU's performance against its own historical performance in lieu of directly comparing an EGU's performance against other EGUs with similar characteristics. Accordingly, as described below, our method effectively controls for the characteristics and factors of an EGU that typically remain constant over time (
a.
In finalizing the building block 1 portion of this rule, we considered over a thousand individual comments from the public, including individual EGUs and state agencies, on heat rate improvement, which are discussed below and also in the responses to comments document and the GHG Mitigation Measures TSD for the CPP Final Rule. Based on these public comments, we have refined the statistical analyses used in the proposal to identify the potential heat rate improvement that can be achieved on average by affected coal-fired EGUs.
In the proposal, we used two approaches to analyze the variability of an EGU's gross heat rate using a robust dataset comprised of 11 years of hourly gross heat rate data for 884 coal-fired EGUs—over 11 million hours of data collected between 2002 and 2012. The foundation of our first approach was an analysis of the variability of each EGU's gross heat rate, which was accomplished in large part by grouping each EGU's hourly data by similar ambient temperature and capacity factor (
We received many comments asserting that the 11-year dataset we had used to determine the 4-percent best practices figure likely reflected some portion of the 2-percent equipment upgrades figure we had separately identified. Accordingly, these commenters claim that the EPA double-counted equipment upgrades in arriving at the full estimate of 6-percent heat rate improvement. Commenters also noted the difficulty, in some cases, of determining whether a heat rate improvement measure is an “equipment upgrade” or “best practice,” such as optimizing soot blowing with intelligent systems, using CO monitors for optimizing combustion, or applying air heater and duct leakage controls.
As noted below in sections V.C.1.b and V.C.3, the EPA acknowledges that some equipment upgrades implemented by EGUs during the 11-year study period are reflected in the hourly heat rate data. Therefore, we made two refinements to our analyses of heat rate improvement potential. First, we refined our statistical approaches to use each EGU's gross heat rate from 2012—the final year of the 11-year study period—as the baseline for calculating heat rate improvement potential. By comparing each EGU's best historical gross heat rate with its 2012 gross heat rate, our analyses account for the enduring effects on heat rate of any equipment upgrades or best practices that an EGU implemented during the study period. Heat rate improvement measures that an EGU maintains in 2012 are reflected in that baseline, and thus are not treated as evidence that the EGU can further improve heat rate. Additionally, in part because of limitations on the information available to us regarding which equipment upgrades have been or could be implemented at individual EGUs, as well concerns about double-counting, we have conservatively decided not to add a separate equipment upgrade component to our estimate of heat rate improvement potential. Nonetheless, we remain confident that additional equipment upgrades
Several commenters criticized the fact that the proposal assessed potential heat rate improvement on a nationwide basis. These commenters suggested instead that we narrow the geographic scope of our analysis, generally identifying a state-by-state approach as a preferred alternative. In light of commenters' concerns about using a single nationwide approach, as well as for reasons described in Section V.A and elsewhere in this preamble, the final rule assesses potential heat rate improvement regionally, within the Eastern, Western and Texas Interconnections.
For the final rule, we performed several analyses to determine what heat rate improvement was achievable in each interconnection from best practices and equipment upgrades. As in the proposal, these analyses used the 11-year dataset of EGU hourly gross heat rate data from 2002 to 2012. As discussed further in the GHG Mitigation Measures TSD, our reliance on these gross heat rate data was reasonable given that (1) these data are the only comprehensive data available to the EPA, and (2) heat rate is proportional to CO
As in the proposal, we used more than one analytical method to evaluate the opportunity for EGUs to reduce their CO
The “efficiency and consistency improvements under similar conditions” approach is a slight refinement of an approach discussed at length in the proposal. As in the proposal, we distributed each hour of gross heat rate data for each EGU into a matrix comprised of 168 bins, based on the ambient temperature and hourly capacity factor of the EGU at the time that hour of gross heat rate data was generated. Each bin represented a 10-degree Fahrenheit (°F) range in ambient temperature (from −20 °F to greater than 110 °F), and a 10-percent range in capacity factor (from 0 percent to greater than 110 percent
As we explained at proposal and as discussed further in the GHG Mitigation Measures TSD, ambient temperature and hourly capacity factor are important conditions that influence heat rate at individual EGUs. By separating the EGU-specific data into bins based on these variables, and only directly comparing data within a bin, we were largely able to control for the influence of those variables on an EGU's heat rate. Accordingly, having controlled for these two external factors, and having already controlled for unit-specific factors affecting heat rate by analyzing the data for each EGU in isolation, we are confident that the remaining variation in each bin's data was primarily driven by factors under the EGU operator's control.
After allocating an individual EGU's data across the bins, we next established a benchmark for each bin based on the best hourly gross heat rate accounting for outliers (
Applying this procedure to all units in our database and averaging the generation-weighted results, we determined that it would be reasonable to conclude that, through application of best practices and equipment upgrades, EGUs on average are at least capable of reducing their CO
In addition to the statistical approach described above, we employed a “best historical performance” approach refined from the proposal, which compared each EGU's best two-year rolling average gross heat rate to that EGU's 2012 average annual gross heat rate.
Finally, we employed the “best historical performance under similar conditions” approach, which combines aspects of the other two approaches. First, as with the “efficiency and consistency improvements under similar conditions approach,” we grouped hourly data for each EGU by ambient temperature conditions and hourly capacity factor. Next, we calculated each EGU's best two-year gross heat rate for each of the 168 ambient temperature-capacity factor bins.
As in the proposal, we additionally analyzed the data with our analytical approaches using one-year averaging periods in place of the two-year averaging periods described above.
Accordingly, we have concluded that a well-supported and conservative estimate of the potential heat rate improvements (and accompanying reductions in CO
No affected coal-fired EGU is specifically required to improve heat rate by any amount as a result of this rule. Rather, as described in section VI, the potential for heat rate improvement is used to determine a CO
In this final analysis, we do not delineate what proportion of the potential heat rate improvement can be expected from equipment upgrades versus best practices;
The performance rates quantified in section VI, below, reflect the region-specific values for heat rate improvement. Although the performance rates are based on the least stringent overall performance rate determined to be reasonable for any region, and are thus based in part on the percentage heat rate improvement identified for the region, this rule does not itself require any specific EGU to implement measures resulting in a specific percentage heat rate improvement. Rather, the percentage heat rate improvement value is merely reflected in the CO
b.
In the proposed rule, we determined that building block 1 measures could on average achieve a 6-percent heat rate improvement from coal-fired EGUs in the U.S. based on a 4-percent heat rate improvement from implementation of best practices and a 2-percent heat rate improvement from equipment upgrades. Based on comments received and refinements made to our methodology for determining potential heat rate improvement from the hourly gross heat rate dataset of 884 coal-fired EGUs, we have applied this methodology on a regional basis and reduced the overall expected percentage heat rate improvement for coal-fired EGUs to 4.3 percent in the Eastern Interconnection, 2.1 percent in the Western Interconnection, and 2.3 percent in the Texas Interconnection.
We received comments on our proposed statistical methodology for determining the CO
In the final rule, the EPA extends the implementation deadline from 2020 to 2022. This additional time will be helpful to the states seeking to conduct more targeted analyses of the nature and extent of heat rate improvements that specific coal-fired EGUs can make, considering specific recent improvements or upgrades, planned retirements of older coal-fired EGUs, and other relevant considerations. The extended deadline will also provide additional time to accommodate
By definition, any heat rate improvement made by EGUs for the purpose of reducing CO
Based on the analyses of technical potential and cost summarized above and in Chapter 2 of the GHG Mitigation Measures TSD, we find that heat rate improvements of 4.3, 2.1 and 2.3 percent are reasonable and conservative estimates of what coal-fired EGUs in the Eastern, Western and Texas Interconnections, respectively, can achieve at a reasonable cost.
Many commenters said that the EPA should have subcategorized by EGU design or operating characteristics for purposes of evaluating potential heat rate improvements under building block 1.
Several studies categorize EGUs broadly by capacity, thermodynamic cycle, fuel rank or other characteristics. We considered subcategorizing the EGUs by their design and fuel characteristics under building block 1. Although grouping by categories does not account for all of the factors that may affect heat rate, it can provide a useful way of understanding the operating profile of classes of coal-fired EGUs and the fleet as a whole. However, we have declined to subcategorize among affected coal-fired EGUs for both technical and practical reasons. First, as discussed above, our assessment of heat rate improvement potential uses a unit-specific data methodology that compares each EGU's performance against its own historical performance. By substantially basing our analysis on these unit-specific assessments, we inherently factor in the effect of numerous design conditions. We also conducted a regression analysis that evaluated the effect of numerous factors on heat rate, and found that subcategorizing would generally make little difference in our analysis. Additionally, subdividing the EGUs into subcategories would reduce the quantity of EGUs used to calculate each average, which would increase the influence of random and atypical variations in the data on the overall averages, and would thus decrease our confidence in the results. Furthermore, as a practical matter, states are free to apportion reductions in a way that reflects any subcategories of their choosing when determining the emission standards for individual affected EGUs. Additionally, commenters assert that because building block 1 is calculated on an average basis, some affected EGUs will have greater potential than others to reduce CO
Many commenters told the EPA that EGUs already have undertaken significant efforts to operate efficiently to provide reliable electric service at the lowest reasonable cost; that they believe they cannot significantly improve heat rate; that best practice maintenance activities are performed on a daily basis, including during maintenance outages that allow for the inspection, cleaning and repair of all equipment; that extensive capital investments have been made to install state-of-the art equipment and replace equipment that is beyond repair; and that their employees continuously monitor and control operating levels in the combustion process to maintain maximum combustion of fuel and to avoid wasting available heat energy. In summary, these commenters say they have expended considerable effort and resources to maintain peak boiler efficiency at all times and, therefore, the 6-percent heat rate improvement proposed for building block 1 is unreasonable to apply to EGUs across the board; the EPA should develop a rule that allows treatment of affected EGUs on a case-by-case basis.
We commend the efforts of those who strive to operate and maintain EGUs in the best possible manner to minimize heat loss and CO
Other commenters said that a 6-percent heat rate improvement overall is too high; that the heat rate improvement from upgrades are double-counted within the data used to determine heat rate improvements from best practices; and that the 2-percent heat rate improvement specifically for upgrades was inappropriately based on “conceptual” improvements from only one study.
We have reduced the 6-percent heat rate improvement from the proposed rule to three regionalized figures of 4.3 percent (Eastern), 2.1 percent (Western) and 2.3 percent (Texas), as discussed above and described in detail in the GHG Mitigation Measures TSD supporting the final CPP. We expect that, on average, affected coal-fired EGUs can at a minimum improve heat rate in these amounts by implementing best practices and equipment upgrades identified in the GHG Mitigation Measures TSD. These overall heat rate improvement figures do not include an estimated percentage heat rate improvement attributable specifically to upgrades. Although we are no longer including in our calculation of building block 1 a separate 2-percent heat rate improvement attributable solely to equipment upgrades, this decision is not because we believe that our initial 2-percent assessment of equipment upgrades was incorrect. To the contrary, the information presented in the S&L study was similar to that in other industry reports and studies—many of which were referenced in the proposal TSD—describing potential heat rate improvements at EGUs from all types of equipment upgrades. However, we recognized that the possibility existed that some limited portion of that 2 percent was also reflected in our statistical analyses of historical gross heat rate data. In order to ensure that our methodology did not double-count an indeterminate amount of heat rate improvement available through equipment upgrades, we conservatively set aside the entire additional 2 percent attributable solely to equipment upgrades. Accordingly, we determined the amount of potential heat rate improvement in the BSER solely from the heat rate analyses described above, which account for improvements through best practices and equipment upgrades that were at some point achieved by an EGU, but not for the full range of best practices and equipment upgrades that are actually available.
Commenters also said that the EPA did not look at important factors that affect heat rate such as coal type, boiler type, cooling water temperature, age, nameplate capacity or the use of post-combustion pollution controls.
Our statistical methodology compared each unit to its own historical performance and, therefore, largely accounts for the effects that a unit's design or fuel characteristics would have on heat rate. As discussed above, our methodology used hourly data from 884 units over an 11-year period (2002-2012) and compared the variability in the heat rate of each individual unit to that unit's own performance. By assessing potential heat rate improvement by first looking at unit-specific data, our methodology inherently factors in the possible effects of design and fuel characteristics (
Although cooling water temperature likely plays an important role in a coal-fired EGU's heat rate, as stated by commenters, there are no consistent quality-assured hourly cooling water temperature data available to the EPA. However, in an effort to determine the potential effect of cooling water temperature on heat rate, we looked at a sample of 45 coal-fired EGUs at 19 facilities for which we had hourly surface water temperature data (used as a surrogate for cooling water) from monitors located nearby and upstream of cooling water intake points. Our analysis found that surface water temperature did explain some of the variation in heat rate, but that surface water temperature is strongly correlated with ambient air temperature—a variable we did control for in our methodology. Because of the strong correlation between ambient air temperature and surface water temperature, the availability of a comprehensive dataset of nationwide hourly ambient air temperature, and the similar explanatory power of surface water temperature and ambient air temperature, it is unlikely that separately addressing cooling water temperature would significantly change the results. Rather, we are confident that our use of hourly ambient air temperature in our analyses adequately addressed any significant impact of cooling water temperature. See the GHG Mitigation Measures TSD supporting the final CPP for further details about this analysis. As described further in that TSD, the other potentially relevant variables for which we did not directly control are unlikely to significantly affect the average heat rate.
Commenters said that the heat rate improvement attributable to upgrades will degrade over time or require repeated and costly further upgrades.
We are aware that some heat rate improvement measures can degrade over time. Like most power plant components, some heat rate improvement technologies require maintenance in order to sustain their efficacy over time. Therefore, to avoid degradation, personnel at EGUs will need to diligently apply “best practices” on a regular basis, a practice that numerous commenters say is standard operating procedure. The S&L study includes estimates of associated operations and maintenance (O&M) costs for each heat rate improvement method that is discussed. As we explained in the proposal, the related O&M costs of diligently applying best practices are relatively small compared to the associated capital costs and would, therefore, have little effect on the economics of heat rate improvements.
Commenters stated that heat rate improvement should be set on a basis that is narrower than nationwide—for example, state-by-state or unit-by-unit.
The EPA did not propose and is not finalizing a rule that sets heat rate improvement goals for individual states or for individual coal-fired EGUs. Instead, in the approved state plans developed under this rule, each state will set the emission standards for its various coal-fired EGUs. In doing so, the state may take into account its own view of the amount of heat rate improvement needed (if any) at specific EGUs, and may look to the EPA's analysis of heat rate improvement potential in the applicable region as a guide, while keeping in mind the CO
The heat rate improvement measures comprising building block 1 would ordinarily be evaluated on a nationwide basis. However, in this instance there are two good reasons to calculate building block 1 on a regionalized basis. First, a regionalized approach is consistent with the EPA's approach to determining the other building blocks. For building block 1, this means that the heat rate improvement should reflect only as much potential for emission reduction from building block 1 as our analyses indicate can be achieved on average by the affected coal-fired EGUs in that region. This ensures that the BSER for each region is representative of the characteristics and opportunities available within that region, rather than a less logical combination of opportunities in the region and opportunities nationwide. Second, a regionalized approach provides a more representative average of the potential heat rate improvement that EGUs in a given region are capable of achieving. The populations of affected coal-fired EGUs in each region differ in some respects, as discussed in the GHG Mitigation Measures TSD, and the more nuanced regionalized approach thus indirectly accounts for some of those systemic differences. For these and other reasons described in Section V.A. of the preamble with respect to the BSER as a whole, we have reasonably based building block 1 on a regionalized approach. Applying this regionalized approach to building block 1 strikes an appropriate balance between the proposed nationwide analysis and commenters' suggested state-specific analysis, which does not fully reflect the interconnected nature of the system within which affected coal-fired EGUs operate.
The practical consequence of calculating building block 1 on a regionalized versus nationwide basis is minimal. This is because the CO
We further note, along with some commenters, that site-specific engineering studies or unit-by-unit analyses of heat rate improvement potential for coal-fired EGUs are not available to the EPA; only a small number of site-specific case studies are available in the public literature. We considered that for the EPA to develop a comprehensive, unit-by-unit heat rate improvement study of nearly 900 coal-fired EGUs from scratch, it would likely cost the Agency $50,000 to $100,000 to study each EGU (almost $50 to $100 million total) and require three to four years to complete. Such a granular analysis would not serve the broader goal-setting purpose of this rulemaking. We agree with commenters who have pointed out that a heat rate improvement-estimating effort of that magnitude and duration would be unnecessarily lengthy and expensive. Nor would such a granular analysis be a necessary predicate for states to develop emission standards, or for EGUs to comply with those emission standards. Rather, our methodology relies on individualized, unit-by-unit hourly performance data from 884 EGUs provides conservative and reasonable regional estimates of heat rate improvement potential. Indeed, given the conservative nature of our methodology, a unit-specific approach that evaluates the full range of best practices and equipment upgrades available at individual EGUs—including upgrades not accounted for here—would be more likely to result in higher overall heat rate improvement figures than we are finalizing for building block 1. Furthermore, site-specific information forms the foundation of the EPA's estimated heat rate improvement potential, and similar data likely would be used in any site-specific heat rate improvement engineering study. Finally, EGU-specific detailed design and operation information is not consistently available for all the factors that influence heat rate. The EPA has used the comprehensive data that are available to reasonably and conservatively estimate potential heat rate improvement in each region.
Commenters also said that shifting electricity generation from coal-fired EGUs to other EGUs because of measures implemented under other building blocks will lower the capacity factors of coal-fired EGUs, and thus increase, not decrease, their heat rates.
We expect that most states will develop plans that optimize the operation of existing coal-fired EGUs while utilizing the other building blocks and other measures to reduce emissions from carbon-intensive generation. From our IPM projections, the average annual capacity factor of existing coal-fired EGUs that are expected to remain in operation in 2030 will actually increase compared to 2012. This projection—which is further described in the GHG Mitigation Measures TSD—incorporates expected retirements of inefficient units and generation shifts away from using coal-fired EGUs as peaking units.
Commenters also noted that the EPA used net heat rate in state goals, but used gross heat rate in its heat rate improvement analysis—potentially ignoring the detrimental effect that parasitic load from air pollution control devices (APCD) and other equipment can have on net heat rate.
The EPA's variability analysis necessarily and reasonably used gross output data for each of the 884 EGUs in the EPA's database because they are the only publicly available, unit-specific, hourly performance data. By definition, improvement in gross heat rate would be reflected in the net heat rate. Gross heat rate is the total heat output from the EGU, in units of Btu/gross kWh, and includes the power used by auxiliary equipment required to operate the EGU itself. By contrast, net heat rate is the remaining Btu/kWh after subtracting the power used by the EGU's own auxiliary equipment from the gross heat rate value,
Commenters also raised concerns that the EPA was not taking into account net heat rate increases due to additional add-on pollution controls that may, for some units, be required by other rules.
The results of our statistical analyses are based on gross heat rates and would not change with installation of emission controls for CSAPR, MATS, or other rules because these controls will add parasitic load requirements and thereby have an impact on the net heat rates only. Furthermore, we conservatively consider region-wide net heat rate
Commenters contended that the 11 years of data used to evaluate potential heat rate improvement is too broad, and that the population of domestic coal-fired EGUs has changed significantly over this time period.
The 11-year span for the hourly gross heat rate data is appropriate because it represents a wide variety of economic conditions, market conditions and fleet composition, while also capturing the relatively recent historical performance of affected coal-fired EGUs. We also noted in the proposal TSD that the population of coal-fired EGUs used in the analytical approaches to determine potential heat rate improvement is made up of coal-fired EGUs that operated in 2012. The gross heat rate data of any coal-fired EGUs that retired prior to 2012 were not included in the dataset.
Commenters stated that many of the changes in heat rate reflected in the 11-year hourly gross heat rate dataset are attributable to changes in monitoring methodology, and thus do not represent heat rate improvements attributable to best practices or equipment upgrades. In addition, commenters are concerned that changes to the monitoring methodology in the future could artificially alter the measured heat rate.
Different stack gas flow monitoring methods can yield more or less accurate measurements of heat input and CO
Some EGUs adopted monitoring methodologies that have the potential to affect the exactness of the data we used for assessing heat rate improvements. However, as discussed in detail in the GHG Mitigation Measures TSD supporting the final CPP, our review of the data shows that a relatively small amount of the data are affected by these changes; we are confident that the values adopted for building block 1 are conservative and reasonable estimates of the potential for heat rate improvement in each region. Some changes in monitoring methodology would have the result of tending to cause us to underestimate the potential for heat rate improvement. Furthermore, because our methodology analyzes percentage heat rate improvement based on 2012 gross heat rate data, our results are unaffected by EGUs that used more accurate monitoring methodologies in 2012 or used the same monitoring methodologies consistently throughout the 11-year study period. For these and other reasons discussed in detail in the GHG Mitigation Measures TSD, we remain confident in our results despite the marginal differences attributable to monitoring methodologies in some of the heat rate data for a subset of EGUs.
In terms of concerns with future methodological changes, the overwhelming majority of the 884 EGUs in the dataset we used to assess heat rate improvement have already changed their stack gas flow monitoring methodology in 2012 or earlier. Furthermore, extension of the compliance date to 2022 for this rule, as discussed above, more than adequately allows enough time for EGUs to determine how to actually improve their heat rates and lower CO
Commenters said that there is no proof that lowering the heat rate will reduce variability or that reduced variability will reduce heat rate,
As an initial matter, it is important to note that for the final rule the EPA used three types of statistical analyses to evaluate and estimate potential heat rate improvements of coal-fired EGUs, and only one of these analyses involved any consideration of heat rate variability. All three types of statistical analyses are described in the GHG Mitigation Measures TSD supporting the final CPP.
These commenters are correct that, in the abstract, reducing heat rate variability only means that heat rate will be more consistent—not necessarily lower or higher. However, our analysis is not an abstract evaluation of the potential to reduce variability, as commenters suggest, but rather is an evaluation of the potential heat rate
The consequence of a reduced heat rate is, of course, a lower rate of CO
Some commenters expressed concern that heat rate improvements could trigger applicability of new source review (NSR) provisions. The relationship of this final rule to other regulatory provisions, including NSR, is discussed in section X of the preamble.
The second element of the foundation for the EPA's BSER determination for reducing CO
This section summarizes the EPA's analysis supporting that definition. We begin by discussing the sector's ability to reduce CO
a.
The ability to shift generation from higher- to lower-emitting sources is compatible with the way EGUs are generally dispatched.
EGUs using technologies with relatively low variable costs, such as nuclear units, are for economic reasons generally operated at their maximum output whenever they are available. Renewable EGUs such as wind and solar units also have low variable costs, but the magnitude and timing of their output generally depend on wind and sun conditions rather than the operators' discretion. In contrast, fossil fuel-fired EGUs have higher variable costs and are also relatively flexible to operate. Fossil fuel-fired EGUs are therefore generally the units that operators use to respond to intra-day and intra-week changes in demand. Because of these typical characteristics of the various EGU types, the primary opportunities for switching generation among existing units available to EGU owners and grid operators generally consist of opportunities to shift generation among various fossil fuel-fired units, in particular between coal-fired EGUs (as well as oil- and gas-fired steam EGUs) and NGCC units. In the short term—that is, over time intervals shorter than the time required to build a new electric generation unit—fossil fuel-fired units consequently tend to compete more with one another than with nuclear and renewable EGUs. The amount of generation shifting from coal-fired EGUs to NGCC units that takes place as a result of this competition is highly relevant to overall power sector GHG emissions, because a typical NGCC unit produces less than half as much CO
b.
Since at least 2000, fossil fuel-fired generation has been shifting from coal- and oil-fired EGUs to NGCC units, both as a result of construction of additional NGCC units, and also as a result of dispatch of pre-existing NGCC units at higher capacity factors. As a result, generation from NGCC EGUs in 2012 reached over four times the level of NGCC generation in 2000, while generation from coal and oil/gas steam EGUs decreased by around one third.
c.
There are a variety of patterns of ownership and operational control of EGUs; these ownership and operational structures influence how EGUs will respond to this building block. However, all owners and operators have the ability to comply by using this building block. In terms of ownership, investor-owned utilities (IOUs) serve about 75 percent of the US population, while consumer-owned utilities serve the remaining 25 percent.
Operational control of the dispatch of power over the electricity grid is superimposed on this pattern of ownership. Prior to electricity restructuring, this dispatch was typically operated by major vertically-integrated utilities or by public power entities. Over the last 15 years, large portions of the power grid are now independently operated by ISOs or RTOs. These entities are regulated by FERC and dispatch power from multiple owners to meet the loads on the bulk power grid.
The combination of multiple ownership and types of operational control adds to the complexity of electricity dispatch, but all affected EGUs, regardless of ownership and type of control, can use this building block to comply with the final rule. The principal difference among the differing entities lies in the types of methods that are available for the affected EGU owner to bring about the shift in generation that will make use of this building block for compliance. There are several alternatives to accomplish this result: The owner of the higher-emitting affected EGU may also own, or have affiliates that own, lower emitting generation and thus reduce its own generation and use its control over these other EGUs to increase their generation; an EGU may be able to reduce its generation and buy replacement power from the market that is lower emitting; or the EGU may be able to reduce its generation and procure generation from a separately-owned lower-emitting EGU. These alternatives will be available in states with either rate or mass-based state plans without any change in their general form. Under a rate-based state plan, an EGU owner may also be able to purchase ERCs and average the ERCs into its emission rate for purposes of demonstrating compliance with its standard of performance. Under standards of performance that incorporate emissions trading, an EGU owner may be able to purchase rate-based emission credits or mass-based emission allowances not needed by other EGUs and use those credits or allowances to help achieve its standard of performance.
The potential to shift generation identified for this building block is entirely consistent with the existing economic dispatch protocols described above. State environmental policies can shift generation in two ways. The first is operational restrictions, such as permit limits on the number of hours that an EGU can operate in order to limit emissions. The second is changes in the relative costs of generation among different types of EGUs related to pollution reduction measures. For example, a regulation that necessitates the use of a control technology that requires the application of a reagent in a certain kind of EGU will increase the variable cost of operating that plant, which in turn may reduce the amount of generation it is called upon to deliver to the grid through security-constrained economic dispatch procedures.
In an organized market, where the system operator dispatches units partly based upon costs, an electric power plant that experiences an increase in its variable costs will tend to operate less than it otherwise would have. For example, market-based pollution control programs require units to hold tradable allowances to authorize their emissions of a regulated pollutant. Such an allowance-holding requirement puts a price on the act of emitting the regulated pollutant, which increases the operating costs of units that emit that pollutant, and thus such units will be dispatched less than they otherwise would without such an allowance-holding requirement. The RGGI is an example of a state program that has this effect. In the present rule, although shifts in the mix of generation to address the costs of pollution control can lead to higher electricity generating costs overall, the EPA analysis shows these costs to be modest and well below their associated benefits.
Many of the NGCC units are owned by the same companies or affiliates that also own steam units. In these cases, changes in EGU generation can be planned by the company or affiliate without the need to engage in separate market transactions with outside parties. Where the affected EGU owner is also the dispatch entity, as in most traditional market structures, the EGU owner will generally have operational control over the unit. Environmental conditions, such as compliance costs or limits on generation, can be factored in with fuel costs for purposes of determining when the unit is committed to be available, how the unit can be most efficiently cycled, and at what level the unit is dispatched.
An analysis of generation data from steam and NGCC units in 2012 shows that 77 percent of the steam generation occurred from an EGU that owned, or that had an affiliate that owned, NGCC generation. Eighty percent of the generation shift potential identified in this building block (increasing NGCC generation up to a 75 percent capacity factor on a net basis to replace steam generation) could occur among these entities that own (either directly or through affiliates) both steam and NGCC generation.
Another alternative available to an affected EGU owner that does not also own NGCC generation is for the higher-emitting affected EGU to reduce its generation and purchase replacement power from the market. In organized markets such as RTOs, it is available through standard practice, because the owner impacts how its EGUs are dispatched based upon how it bids into the RTO market. In this case, the owner can exercise control over the levels of generation across units by when it offers generation to the market operator (the RTO or ISO), and the prices it bids for this generation. As in traditional economic dispatch by a utility, environmental conditions, compliance
In regions with organized electricity markets (including, but not limited to, RTOs or ISOs), the various types of EGU owners of higher-emitting sources can reduce their generation, and any resulting deficit in generation on the system can be supplied from other EGUs in the region; for example, a coal-fired unit can reduce generation that is then replaced through the operation of the market by generation from an NGCC unit, subject to dispatch by a regional operator to ensure the reliable delivery of the generation to loads within the region. To comply with this rule, higher-emitting steam units will need greater emission reductions relative to lower-emitting NGCC units which will, in turn, tend to raise steam unit costs compared to NGCC units. As a result, the bids that a steam unit provides a market operator will rise relative to NGCC units. This process of reducing generation from a higher-emitting unit will lead to substitution of lower-emitting generation.
EGU owners that do not participate in an organized electricity market may nevertheless purchase power from the wholesale power market. Purchases in the wholesale power market can be spot purchases, which are typically general purchases of system power supplied by the EGUs across a region, or contract purchases, which may have more provider-specific characteristics (such as specifying the type of unit that is providing the power). Purchases between EGUs through the wholesale power market will have similar emission-lowering properties as operation of the organized market discussed above, because dispatch in balancing areas outside RTOs and ISOs also follows a similar economic dispatch protocol that is informed by each unit's production costs and environmental limitations.
Under this alternative, the steam generators may, in effect, realize emission reductions from building block 2 simply by reducing their generation. Steam generators do not need to purchase replacement electricity as a prerequisite for realizing emission reductions from reducing their own generation because other generators already have an incentive to provide as much electricity as load-serving entities are willing to buy in order to satisfy electricity demand.
An owner of a source can also reduce the generation of an EGU by substituting generation from a lower-emitting NGCC directly. For an EGU owner without existing NGCC generation, this substitution can take the form of a bilateral contract purchase. In RTOs and ISOs, this alternative often takes the form of a contract for differences, where the replacement source could be an NGCC and the contract specifies a delivery location and the price of the power. In bilateral markets, the contract vehicle could be a Power Purchase Agreement from a replacement source. It is also possible that the owner of a steam unit could directly invest in an existing EGU by purchasing the asset or taking a partial ownership position, thus acquiring the generation from the unit through that means. The acquired generation and its associated emissions could be used for compliance by the higher-emitting EGU, in accordance with the plan under which it is operating. The amount of generation that could be shifted using the approaches described in this paragraph will depend on the type and terms of the commercial arrangements, as well as the potential need for regulated entities to obtain approvals for contracts or for changes in asset positions. The wide range of approaches permitted by this rule provides flexibility, both within a year and across multiple years, for EGUs to fashion these arrangements to fit their circumstances.
Where permitted under its state plan, an EGU would also be able to meet its reduction obligations using ERCs or allowances. The particular nature of this alternative will depend on how a state elects to develop its plan. If a state chooses a mass-based approach, the EGU would simply need to hold allowances to cover its emissions. To realize an emission reduction from building block 2 under this approach, a steam generator would only need either to reduce its emissions by reducing its generation, which would lead to that generator needing fewer allowances to cover its emissions under the program, or to purchase surplus allowances not needed by another EGU that had reduced its emissions. In a rate-based state, the state may choose to provide for compliance through the acquisition of tradable ERCs. To realize an emission reduction from building block 2 under this approach, a steam generator would be able to adjust its effective emission rate by purchasing ERCs that are produced by other sources whose emission rates are lower than the applicable rate standard. In this fashion, a steam generator does not need to purchase lower-emitting replacement power per se in order to demonstrate an emission reduction from this building block; instead, the steam generator may purchase any ERCs that were produced from lower-emitting sources (see section VIII for more detail on how state plans can use an ERC approach to facilitate a rate-based compliance demonstration of this type of emission reduction).
The approaches shown here collectively demonstrate that all steam generators—regardless of size, location, form of ownership, or type of market in which they operate—can implement building block 2 through some or all of the mechanisms described.
The EPA has determined that for purposes of quantifying the CO
The EPA received significant public comments expressing concern regarding the proposal's incorporation of the full building block 2 shift in generation by the first year of the interim period. These commenters perceived this approach as requiring states to achieve such a significant portion of the required CO
In the proposal, the EPA determined that emission reductions are feasible and achievable at fossil fuel-fired steam EGUs by shifting from more carbon-intensive EGUs to less carbon-intensive EGUs, as part of the BSER. More specifically, the EPA proposed that generation shifts from fossil fuel-fired steam units (which are primarily coal-fired) to NGCC units, up to a utilization of 70 percent on a nameplate capacity basis, could be achieved by 2020. In contrast, the EPA proposed that reductions in CO
As already noted, in the final rule the EPA has revised the interim period to start in 2022, which itself is a meaningful response regarding the concerns expressed by commenters about the timing of building block 2's generation shift potential. In addition, the EPA has evaluated the feasibility over time of building block 2 within the framework of BSER, and is finalizing a change to building block 2 that gradually phases in the shift from existing fossil steam to existing NGCC over the interim period. This phase-in allows for additional time to complete potential infrastructure improvements (
The phase-in schedule applies a limit to the maximum building block 2 potential in each year of the interim period based on two parameters. The first parameter defines an amount of generation shift to existing NGCC capacity that is feasible by 2022, and the second parameter defines how quickly that amount could grow until the full amount of NGCC generation could be achieved as part of the BSER. Both of these parameters are determined by examining the extent to which gas-fired generation has increased over historical time periods. The first parameter is based on the single largest annual increase in power sector gas-fired generation since 1990, which occurred between 2011 and 2012 and is equal to 22 percent.
In the performance rate calculation methodology, these two parameters constrain the annual rate at which building block 2 shifts generation from fossil steam units to NGCC units. The interim performance rate is an average of annual rates calculated over the 2022-2029 period. The two parameters above limit the extent to which NGCC generation is able to increase and replace fossil steam generation in each year of the interim period. In the first year, NGCC generation is limited to a maximum of a 22 percent increase from 2012 levels in each region. In each subsequent year, regional NGCC generation is limited to a maximum of a 5 percent increase from the previous year. This phase-in continues in the performance rate-setting methodology until the full building block 2 level of shifting from fossil steam generation to NGCC generation is reached. Under this approach, building block 2 is completely phased into the source category calculation of all regions by the end of the interim period.
a.
In order to estimate the potential magnitude of the opportunity to reduce power sector CO
We also researched historical data to determine the utilization rates that NGCC units have already demonstrated their capability to sustain. Over the last several years, the utilization patterns of fossil fuel-fired units have shifted relative to historical dispatch patterns, with NGCC units increasing generation and many coal-fired EGUs reducing generation. In fact, in April 2012, for the first time ever the total quantity of electricity generated nationwide from natural gas was approximately equal to the total quantity of electricity generated nationwide from coal.
Utilization of EGUs is often considered using the metric of a capacity factor, which is the percentage of total production potential that an electric generating unit achieves in a given time period. A capacity factor of 75 percent thus represents a unit producing three-quarters of the electricity it could have produced in that time had it utilized its entire capacity. The EPA received multiple comments regarding the proposed use of nameplate capacity in calculating the potential utilization level of existing NGCCs under building block 2. These comments stated that net summer capacity is a more meaningful and reliable metric than nameplate capacity, because net capacity best reflects the electric output available to serve load. The EPA agrees with these comments. The quantification of building block 2 as well as performance rate and state goal calculations in the final rule are all based on net summer generating capacity. An annual utilization rate of 75 percent on a net summer basis is similar to the proposed rule's consideration of 70 percent utilization on a nameplate basis.
The experience of relatively heavily-used NGCC units provides an additional indication of the degree of increase in average NGCC unit utilization that is technically feasible.
The EPA reexamined the historical NGCC plant utilization rate data reported to the EIA, and found that in 2012 roughly 15 percent of existing NGCC plants operated at annual utilization rates of 75 percent or higher on a net summer basis.
The EPA believes that an annual average utilization rate of 75 percent on a net summer basis is a conservative assessment of what existing NGCC plants are capable of sustaining for extended periods of time. In 2012, roughly 10 percent of existing NGCC plants operated at annual utilization rates of 80 percent or higher on a net summer basis. While the EPA believes this level is also technically feasible on average for the existing NGCC fleet, the EPA is quantifying building block 2 assuming an NGCC utilization level of 75% on a net summer basis in order to offer sources additional compliance flexibility, given that the extent to which they realize a utilization level beyond 75 percent will reduce their need to rely on other emission reduction measures or building blocks.
b.
In 2012, total electric generation from existing NGCC units was 966 TWh.
The EPA believes that producing this quantity of generation from this set of NGCC units is feasible. To put this level of generation into context, NGCC generation increased by approximately 439 TWh (an 83 percent increase) between 2005 and 2012. The EPA calculates that assumed NGCC generation in 2022 through the quantification of building block 2 potential is approximately 44 percent higher than 2014 levels. This reflects a smaller growth rate in potential NGCC generation between 2015 and 2022 than has been observed in practice from 2005 to 2012, a time period of the same duration.
c.
We also expect that an increase in NGCC generation of this amount would not impair power system reliability. Sources can achieve increases in utilization of existing NGCCs that displace generation from steam sources without impacting reliability because this shift in average annual utilization across existing EGUs does not inhibit the power sector's ability to maintain adequate dispatchable resources to continue to meet reserve margins and maintain reliability. Furthermore, sources are not required to achieve the exact or even the full extent of the building block 2 generation shift itself, which means that sources will have ample flexibility to maintain reliability-relevant operations while achieving emission reductions through a variety of measures.
d.
The EPA also examined the technical capability of the natural gas supply and delivery system to provide increased quantities of natural gas and the capability of the electricity transmission system to accommodate shifting generation patterns. For several reasons, we conclude that these systems would be capable of supporting the degree of increased NGCC utilization potential in building block 2. First, the natural gas pipeline system is already supporting national average NGCC utilization rates of 60 percent or higher during peak hours, which are the hours when constraints on pipelines or electricity transmission networks are most likely to arise. NGCC unit utilization rates during the range of peak daytime hours from 10 a.m. to 9 p.m. are typically 15 to 20 percentage points above their average utilization rates (which have recently been in the range of 40 to 50 percent).
The second consideration supporting a conclusion regarding the adequacy of the gas supply infrastructure is that pipeline and transmission planners have repeatedly demonstrated the ability to methodically relieve bottlenecks and expand capacity.
e.
We recognize that an increase in NGCC utilization rates at existing units corresponds with an associated increase in natural gas production, consistent with the current trends in the natural gas industry. The EPA expects the growth in NGCC generation assumed for building block 2 to be feasible and consistent with the production potential of domestic natural gas supplies. Increases in the natural gas resource base have led to fundamental changes in the outlook for natural gas. There is general agreement that recoverable natural gas resources will be substantially higher for the foreseeable future than previously anticipated, exerting downward pressure on natural gas prices. According to EIA, proven natural gas reserves have doubled between 2000 and 2012. Domestic dry gas production has increased by 25 percent over that same timeframe (from 19.2 TCF in 2000 to 24.0 TCF in 2012).
The EPA has also assessed the ability of the electricity and natural gas industries to achieve the potential quantified for building block 2 using the Integrated Planning Model (IPM). IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector that the EPA has used for over two decades to evaluate the economic and emission impacts of prospective environmental policies. To inform its projections of least-cost capacity expansion and electricity dispatch, IPM incorporates representations of constraints related to fuel supply, bulk power transmission capacity, and unit availability. The model includes a detailed representation of the natural gas pipeline network and the capability to project economic expansion of that network based on pipeline load factors. At the EGU level, IPM includes detailed representations of key operational limitations such as turn-down constraints, which are designed to account for the cycling capabilities of EGUs to ensure that the model properly reflects the distinct operating characteristics of peaking, cycling, and base load units.
As described in more detail below, the EPA used IPM to assess the costs of increasing generation from existing NGCC capacity. IPM was able to meet average NGCC utilization rates of 75 percent on a net summer basis, while observing the market, technical, and regulatory constraints represented in the model. This modeling also demonstrates the ability of domestic natural gas supplies to increase their production levels, and deliver that supply through the pipeline network, to support the level of NGCC generation quantified in building block 2. Such a result is consistent with the EPA's determination that increasing the average utilization rate of existing NGCC units to 75 percent would be technically feasible.
f.
Achieving the generation shift quantified in building block 2 would not impose significant additional burden on the transmission planning process and does not necessitate major construction projects. Two considerations are important for this conclusion:
First, building block 2 applies only to increases in generation at
g.
The final consideration supporting our view that natural gas and electricity system infrastructure would be capable of supporting increased NGCC unit utilization rates at a maximum of 75% on a net summer basis is the substantial unit-level compliance flexibility of the emission guidelines. The final rule does not require any particular NGCC unit to achieve any particular utilization rate in any specific hour or year. Thus, even if isolated natural gas or electricity system constraints were to limit NGCC unit utilization rates in certain locations in certain hours, this would not prevent an increase in NGCC generation overall across a state or broader region and across all hours on the order assumed in the generation shift potential quantified for building block 2.
Having established the technical feasibility and quantification of the potential to replace incremental generation at higher-emitting EGUs with generation at NGCC facilities as a CO
To consider the cost implications of building block 2, the EPA expanded upon the proposal's extensive analysis of the magnitude and cost of CO
To evaluate how EGU owners and grid operators could respond to a state plan's possible requirements, signals, or incentives to shift generation from more carbon-intensive to less carbon-intensive EGUs, the EPA analyzed a series of scenarios in which the fleet of NGCC units within each of the regions considered for quantifying BSER (
The costs of the various scenarios were evaluated by comparing the total costs and emissions from each scenario to the costs and emissions from a base case scenario. For the scenario reflecting a 75 percent NGCC utilization rate on a net basis with regional fossil generation shifting, comparison to the base case indicates that the average cost of the CO
We also conclude from these analyses that potential impacts to fuel prices and electricity prices from achieving the extent of fossil generation shifting quantified for this building block are reasonably within the bounds of power sector experience. For example, in the 75 percent NGCC unit utilization rate scenario where generation shifting is limited to regional boundaries, the delivered natural gas price was projected to increase by an average of 7 percent over the 2022-2030 period, which is well within the range of historical natural gas price variability.
However, we also note that the costs (and their incorporated price impacts) just described are higher than we would expect to actually occur in real-world compliance with the final rule's compliance requirements for the following reasons. First, this analysis does not capture the building block 2 phase-in, which assumes an average utilization rate over the interim period of less than 75 percent in all three interconnections. Second, the analysis overstates the extent to which building block 2 is ultimately reflected in the source category performance rates. While the performance rate computation procedure assumes a maximum NGCC utilization rate of 75 percent on a net summer basis, the Eastern Interconnection's realization of this level of NGCC utilization yields higher source category performance rates for steam than what would have been calculated for units in the Western Interconnection and Texas Interconnection if they realized that maximum NGCC utilization rate in conjunction with the other building blocks. In other words, there is substantial building block 2 potential in the Western Interconnection and Texas Interconnection that is not actually captured in the source category performance rates that are ultimately assigned to steam through this rate- and goal-setting approach (where the performance rates are ultimately determined by the BSER region with the highest rate outcome in the calculation). Therefore, the building block 2 analysis overstates the cost of this component of BSER to the extent that it assumes achievement of this generation shift potential that is not reflected in the source category performance rates ultimately determined. Third, as a practical matter, sources will be able to achieve additional emission reductions through other measures that may prove to be less costly than generation shifting and could substitute for the reductions and costs considered here. These building block 2 analyses were focused on evaluating the potential impacts of fossil generation shifting in isolation, and as a result, they do not consider states' and sources' flexibility to choose among alternative CO
Based on the analyses summarized above, the EPA concludes that an average annual utilization rate for each region's NGCC units of up to 75 percent is a technically feasible, cost-effective, and adequately demonstrated building block for BSER.
For further information on the analysis discussed in this section, see Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule.
The EPA received numerous comments regarding building block 2. Many of these comments provided helpful information and insights and have resulted in improvements to the rule. This section summarizes some of these comments, and the remainder of the comments are responded to in the Response to Comment document, available in the docket.
The EPA received comment regarding the potential for an increase in upstream methane emissions from increased utilization of natural gas. Our analysis found that the net upstream methane emissions from natural gas systems and coal mines and CO
Commenters also expressed concern that neither a utility nor any state agency controls dispatch in most states. The EPA believes these comments fail to adequately appreciate that the utilities do control the dispatch of units that they own and/or operate, either by being the actual dispatch agent in many cases where there is no RTO or ISO that schedules the dispatch, or by the choice of units and bids they offer into an organized electricity market operated by an RTO or ISO. These entities currently control the dispatch of their units while respecting all existing requirements from environmental rules. This final rule does not change these current circumstances and makes clear that it is the EGU that is responsible for meeting the requirements in the state plan; the state is responsible for the development of that plan, but the state does not need to control the dispatch.
Other comments object to the use of a single capacity factor for all existing NGCCs to quantify building block 2 potential on the grounds that not all units may be able to achieve this utilization level, and that some units may be designed for cycling and so may need upgrades to sustain such utilization. The EPA disagrees with these comments. The 75 percent capacity factor establishes a regional potential for generation from existing NGCC capacity, and it does not establish any individual unit requirements.
Some comments argue that generation limits in permits for some existing NGCC units will limit the amount by
The EPA also received comments asserting that increasing generation from new renewables would require increased use of natural gas capacity for back-up and ramping, and therefore it is not possible for NGCC units to run at BSER utilization rates and also be available to support the additional variable renewable generation resulting from building block 3. The EPA disagrees with this comment. The 75% net summer utilization rates defined by building block 2 is a conservative assessment and applied on an annual average basis. It is therefore possible for these existing units to both operate at higher annual utilization rates, and also to operate at higher rates during limited periods and still maintain a 75% net summer average annual utilization rate. While variable renewable generation does require additional load following and ramping resources and unit cycling, these requirements are generally a small part of the overall ramping costs of the system (see NREL, Relevant Studies for NERC's Analysis of EPA's Clean Power Plan 111(d) Compliance). Additionally, while existing NGCC units are an efficient source of ramping to support variable renewables, other units running in an intermediate mode can also provide load following and ramping.
The third element of the foundation for the EPA's BSER determination for reducing CO
In this section we address first the history of and then trends in RE development, as well as the importance of expanding the use of RE. Next we discuss the ability of affected EGUs to access generation from new RE generating capacity, followed by a discussion of renewable energy certificate (REC) markets. We then describe the quantification of the amount of generation from new RE generating capacity achievable through building block 3, including key comments, changes made from the proposal, the method by which RE target generation levels are quantified, and the magnitude and timing of increases in RE generation associated with this building block. Next, we discuss the feasibility of implementing the identified incremental amounts of RE generation. Finally, we address the costs associated with those increases in RE generation.
RE generating technologies are a well-established part of the utility power sector. These technologies generate electricity from renewable resources, such as wind, sun and water. While RE has been used to generate electricity for over a century, the push to commercialize RE more broadly began in the 1970s.
PURPA was a key step in stimulating RE development. By requiring utilities to purchase generation from qualifying facilities (
States have also taken a significant lead in requiring the development of RE resources. In particular, a number of states have adopted renewable portfolio standards (RPS), which are regulatory mandates to increase production of RE. As of 2013, 29 states and the District of Columbia had enforceable RPS or similar laws.
Today, RE is tightly integrated with the utility power sector in multiple ways: States have set RE targets for electrical load serving entities; utilities themselves are diversifying their portfolios by contracting with RE generators; and new RE generators are being developed to provide more electrical power grid support services beyond just energy (
Use of RE continues to grow rapidly in the U.S. In 2013, electricity generated from RE technologies, including conventional hydropower, represented 12 percent of total U.S. electricity, up from 8 percent in 2005.
The global market for RE is projected to grow to $460 billion per year by
The recent and projected growth of RE is in part a reflection of its increasing economic competitiveness. Numerous studies have tracked capital cost reductions and performance improvements for RE, particularly for solar and wind. For instance, Lazard's analysis of wind and utility-scale solar PV levelized costs of energy (LCOE), on an unsubsidized basis, over the last five years found the average percentage decrease of high and low of LCOE ranges were 58 percent and 78 percent, respectively.
Currently, the utility power sector accounts for 40 percent of total annual energy consumption in the U.S.
A number of studies and recent policy developments have acknowledged RE as an important means of achieving CO
Increased use of RE provides numerous benefits in addition to lower CO
Increasing RE use will also continue to lower other air pollutants (
The ability of affected EGUs to co-locate or obtain incremental RE to reduce CO
Owners and operators of affected EGUs across the U.S. already have substantial opportunities to procure RE regardless of their organizational structure and/or business model. In many parts of the country, EGUs are owned and operated by vertically integrated utilities. These utilities can be investor-owned utilities that operate under traditional electricity regulation, municipal utilities (munis), or electric cooperatives (co-ops). These utilities have significant control over the types of generating capacity they develop or acquire, and over the electricity mix used to meet demand within their service territories.
Even when EGU owners participating in organized markets do not directly determine dispatch among energy sources, such EGU owners make
Many affected EGUs have already directly invested in RE. Of the 404 entities that owned part of at least one affected EGU under this rule, 178 also owned RE (biomass, geothermal, solar, water or wind). These 178 owners owned 82 percent of affected EGU capacity. As a whole, these entities' share of RE capacity was equal to 25 percent of the total of their affected EGU capacity.
Some of the largest owners of affected EGUs also owned RE (see Table 8). For example, NRG Energy, Inc. owns more than 3,000 megawatts of RE capacity, over 20 percent of which (nearly 800 megawatts) is solar, and almost 80 percent of which (over 2,500 megawatts) is wind. Duke Energy Corporation owns 175 megawatts of solar and over 1,500 megawatts of wind. NextEra Energy, Inc.'s share of RE capacity approaches 40 percent of their total affected EGU capacity.
Large
The list of ten electric utilities with the largest amounts of wind power capacity on the system (owned or under contract) includes a variety of affected EGU organizational structures, including vertically integrated investor-owned utilities, municipal utilities, and federal power authorities. Xcel Energy and Berkshire Hathaway Energy rank first and second with 5,736 megawatts and 4,992 megawatts of wind capacity, respectively. Tennessee Valley Authority, a federal power authority, had 1,572 megawatts and CPS Energy, a public utility, had 1,059 megawatts of wind power capacity.
Many affected EGUs are already planning on deploying significant amounts of RE according to their integrated resource plans (IRPs). Electric utilities use IRPs to plan operations and investments over long time horizons. These plans typically cover 10 to 20 years and are mandated by public utility commissions (PUCs). A recent study of IRPs, included in the docket for this rulemaking, shows this trend.
Independent power producers (IPPs) also can and do own both RE and fossil generation. For example, NRG is a diversified IPP that operates substantial coal, natural gas, wind, solar, and nuclear capacity. NRG demonstrates the ability of IPPs to reduce utilization of fossil fuel-fired EGUs and replace that generation with RE. NRG announced a goal to cut CO
EGU owners can also replace fossil fuel-fired generation with RE through bilateral contracts and REC purchases, as described below. Both the bilateral market for RE contracts and REC markets are well-developed. There are no legal or technical obstacles to a fossil fuel-fired EGU owner acting as the counterparty of a bilateral contract for purchase of energy from a RE facility. Any type of EGU owner (utility or otherwise) can purchase and retire RECs. The fact that RECs are purchased by a diverse set of market participants—including residential consumers, commercial businesses, and industrial facilities—demonstrates that such a purchase for all EGU owners is adequately demonstrated.
Affected EGU owners do not need to directly invest in, or own, renewable generating capacity in order to replace fossil fuel-fired generation with RE as an emission reduction measure. RECs are used to demonstrate compliance with state RE targets, such as state RPS, and also to substantiate claims stemming from RE use. RECs are tradable instruments that are associated with the generation of one megawatt-hour of RE and represent certain information or characteristics of the generation, called attributes.
The legal basis for RECs is established by state statutes and administrative rules. Nearly all states with a mandatory RPS have established RECs as a means of compliance. The Federal Energy Regulatory Commission (FERC) has observed that states created RECs to facilitate programs designed to promote increased use of RE, and that “attributes associated with the [RE] facilities are separate from, and may be sold separately from, the capacity and energy.”
In complying with states' RPS requirements, utilities have contracted for RECs from in-state and out-of-state resources in accordance with RPS requirements. Utilities may have sourced RECs from out-of-state to reduce the cost of compliance, to source RECs from specific generation types, or for other reasons.
The development of REC markets to facilitate RPS compliance provides evidence that markets can develop to facilitate compliance with rate-based state plans. These markets will afford affected EGU owners an alternative to directly invest in, or own, renewable generating capacity in order to replace fossil fuel-fired generation with RE as an emission reduction measure.
The methodology for quantifying RE generation levels under building block 3 is a modified version of the alternative RE approach from proposal, with adjustments that reflect the data and information the EPA collected through stakeholder comments and the EPA's additional analysis and information collection. In evaluating the proposed and alternative RE approaches commenters observed that RPS, as the basis for quantifying RE generation levels under the proposed approach, are policy instruments that states may choose to implement for a variety of reasons not related to CO
Within the framework of the alternative RE approach, the EPA received significant comments on a number of issues, including the use of historical deployment rates, the interstate nature of RE and the power system, merits of total versus incremental RE generation as the metric by which building block 3 generation levels are quantified, types of RE technologies that contribute to those generation levels, cost and performance estimates associated with those RE technologies, magnitude of the reduced cost applied to new RE capacity as an incentive to deploy, and application of a nationally uniform benchmark development rate to modeled projections of economic deployment. Based on commenter data and information, as well as further analysis and information collection, the primary adjustments the EPA made to the alternative RE approach are:
• The basis for quantifying building block 3 generation has been modified to incorporate historical deployment patterns for RE technologies as well as the economic potential identified through modeling projections. The introduction of historical capacity additions to the final methodology further grounds building block 3 generation
• The RE technologies used to quantify building block 3 generation levels are onshore wind, utility-scale solar PV, concentrating solar power (CSP), geothermal and hydropower. Each of these technologies is a utility-scale, zero-emitting resource that was included under the alternative RE approach at proposal. Additionally, the EPA received significant comments on the opportunities and challenges associated with distributed RE technologies. Distributed technologies, as a demand-side resource, present unique data and technical challenges (such as the role of evaluation, measurement and verification (EM&V) procedures in verifying their production, the diverse economic incentives of different parties involved in their deployment, and the variety of grid integration policies and conditions across potential deployment sites) that complicate identifying a technically feasible and cost-effective level of generation. Consequently, the EPA is, at this time, choosing not to include distributed technologies as part of the BSER (although, as explained in section VIII.K of this preamble, distributed RE technologies that meets eligibility criteria may be used for compliance). Finally, any RE technology that has not been deployed in the U.S., including demonstrated RE technologies for which there is clear evidence of technical feasibility and cost-effectiveness (
• Building block 3 generation levels are expressed in terms of incremental, rather than total, RE generation. As a metric, incremental generation is better aligned with quantifying an amount of expanded RE to replace generation at affected EGUs.
• Due to the interstate nature of RE and the power system, and consistent with the rationale provided in the October 2014 Notice of Data Availability (NODA), building block 3 generation levels are quantified for each of the three BSER regions—the Eastern Interconnection, Western Interconnection, and Texas Interconnection—rather than at the state-level. This regionalized approach, as described in the NODA, takes into account the opportunity to develop regional RE resources and thus better aligns building block 3 generation levels with the rule's approach to allowing the use of qualifying out-of-state renewable generation for compliance.
• Commenters observed that the cost and performance estimates the EPA relied on at proposal from the Energy Information Administration's Annual Energy Outlook 2013 do not reflect the decline in cost and increase in performance that have been demonstrated by current projects, particularly in regards to wind and solar technologies. Commenters provided data from a variety of sources to support these claims, including Lawrence Berkeley National Laboratory (LBNL), the Department of Energy (DOE) and Lazard. Each of these sources supported the contention that RE technologies, particularly wind and solar, have realized gains in cost and efficiency at a scale that has altered the competitive dynamic between RE and conventional resources. As a result, it has become increasingly necessary for any long-term outlook of the utility power sector to continually assess the development of RE technology cost and performance trends. In performing this task, the EPA revised its data for onshore wind and solar technologies to reflect the mid-case estimates from the National Renewable Energy Laboratory's (NREL's) 2015 Annual Technology Baseline. The EPA selected the NREL 2015 Annual Technology Baseline (ATB) estimates based on the quality of its data as well as NREL's demonstrated success in both reflecting and anticipating RE cost and performance trends. In addition to wind and solar technologies, the EPA evaluated hydropower deployment potential based on the latest cost and performance data from NREL's Renewable Energy Economic Potential study.
• The benchmark development rate that constrained cost-effective RE deployment under the alternative RE approach in the proposal has been removed from the final methodology.
In addition to the comments described above, the EPA received significant comments on a wide variety of topics related to building block 3. Many of these comments provided helpful information and insights, and have resulted in improvements to the final rule. These comments, as well as the EPA responses, are available in the Response to Comment document.
The final methodology for quantifying incremental RE target generation levels contains seven steps. Each step is described below.
First, the EPA collected data for each RE technology (onshore wind, utility-scale solar PV, CSP, geothermal and hydropower) to determine the annual change in capacity over the most recent five-year period. From these data, the EPA calculated the five-year annual average change in capacity and the five-year maximum annual change in capacity for each technology.
Second, the EPA determined an appropriate capacity factor to apply to each RE technology that would be representative of expected future performance from 2022 through 2030. For this purpose the EPA relied on NREL's ATB.
Third, the EPA calculated two generation levels for each RE technology. The first generation level is the product of each technology's five-year average capacity change and the assumed future capacity factor. The second generation level is the product of each technology's five-year maximum annual capacity deployment and the assumed future capacity factor. Table 9 below shows the data and assumptions used for these calculations.
Fourth, the EPA quantified the RE
Fifth, the EPA applied the generation associated with the five-year average capacity change to the first two years of the interim period. Combining the projected 2021 RE generation from capacity starting operation after 2012 with the generation increment associated with the five-year average change in capacity produces 241,880,347 megawatt-hours in 2022 and 270,676,570 megawatt-hours in 2023. The EPA believes it is appropriate to apply the generation associated with the five-year average capacity change for the first two years of the interim period to ensure adequate opportunity to plan for and implement any necessary RE integration strategies and investments in advance of the higher RE deployment levels assumed for later years.
Sixth, for all years subsequent to 2023 the EPA applied the generation associated with the maximum annual capacity change from the historical data analysis. In 2024, this produces a building block 3 generation level of 332,869,933 megawatt-hours (aggregated across all three BSER regions); by 2030, that generation level is 706,030,112 megawatt-hours.
Seventh, to further evaluate the technical feasibility and cost-effectiveness of the building block 3 generation levels (aggregated across all three BSER regions), as well as to produce interconnection-specific levels of building block 3 generation from the national totals described in steps 5 and 6, the EPA conducted analysis using IPM of a scenario directing the power sector to achieve those RE generation levels. IPM modeling projections assess opportunities for RE deployment in an integrated framework across power, fuel, and emission markets. The modeling framework incorporates a host of constraints on the deployment of RE resources, including resource constraints such as resource quality, land use exclusions, terrain variability, distance to existing transmission, and population density; system constraints such as interregional transmission limits, partial reserve margin credit for intermittent RE installations, minimum turndown constraints for fossil fuel-fired EGUs, and short-term capital cost adders to reflect the potential added cost due to competition for scarce labor and materials; and technology constraints such as construction lead times and hourly generation profiles for non-dispatchable resources by season.
Grid Integration and the Carrying Capacity of the U.S. Grid to Incorporate Variable Renewable Energy. NREL. Cochran et al., April 2015.
The Western Wind and Solar Integration Study Phase 2. NREL. Lew et al., 2013. Available at
In addition to facilitating the EPA's assessment of the feasibility and cost of reaching the aggregate building block 3 generation levels across all three BSER regions, the IPM projections also provide the EPA with a basis for apportioning those generation levels to each interconnection. The EPA considered the projected regional location of the evaluated RE deployment in this analysis, which shows the
Through the quantification methodology detailed above, the EPA has identified amounts of incremental RE generation that are reasonable, rather than the maximum amounts that could be achieved while preserving the cost-effectiveness of the building block. For example, assuming gradual improvement in RE technology capacity factors consistent with historical trends, expanding the portfolio of RE technologies that contribute to the building block 3 generation level, and applying the five-year maximum capacity change values to all years of the interim period are adjustments that would produce higher building block 3 generation levels and maintain the primacy of historical data in quantifying RE generation potential. External analysis and studies of RE penetration levels strongly support the technical feasibility and cost-reasonableness of RE deployment well in excess of the levels established by building block 3, as detailed in section V.E.7. By identifying reasonable rather than maximum achievable amounts, we are increasing the assurance that the identified amounts are achievable by the source category and providing greater flexibility to individual affected EGUs to choose among alternative measures for achieving compliance with the standards of performance established for them in their states' section 111(d) plans.
The 2030 level of RE deployment and the rate of progress during the interim period in getting to that level are well supported by comments received, DOE and NREL analysis, and external studies evaluating the costs of and potential for RE penetration. The EPA has assessed the feasibility of RE in terms of deployment potential, system integration, reliability, backup capacity, transmission investments, and RE supply chains.
Historical RE deployment rates are a strong indication of the feasibility of the 2030 level of deployment and interim period pathway. The use of RE continues to grow rapidly in the U.S. In 2013, electricity generated from RE, including conventional hydropower, represented 12 percent of total U.S. electricity, up from 8 percent in 2005. In particular, there has been substantial growth in the wind and solar markets in the past decade. Since 2009, wind energy has tripled and solar has grown tenfold.
The expected future capacity installations in 2022-2030 needed to reach the 2030 level of incremental RE generation are consistent with historical deployment patterns. Forecasts by Cambridge Energy Research Associates (CERA) of 17 gigawatts in 2015 and historical deployment of 16 gigawatts in 2012 are significant. The average deployment of wind over the past five years was 6,200 megawatts per year; 2014 deployment of solar PV, both distributed and utility-scale, was 6,201 megawatts. This contribution from solar PV is consistent with the rapid reduction in costs that is currently being observed and is expected to continue.
Grid operators are reliably integrating large amounts of RE, including variable, non-dispatchable RE today. For example, Iowa and South Dakota produced more than 25 percent of their electricity from wind in 2013, with a total of nine states above 12 percent and 17 states at more than 5 percent. California served nearly 19 percent of total load in 2013 with RE resources, not including behind-the-meter distributed solar resources, and approximately 25 percent of total load with RE in 2014. On an instantaneous basis, California is regularly serving above 25 percent of load with RE resources, recently began seeing over 5,000 megawatt-hours of solar energy, and is on track for 33 percent of load with no serious reliability or grid integration issues. Germany exceeded 28 percent non-hydro RE as a percentage of total energy in first half of 2014. Other recent examples include: ERCOT met 40 percent of demand on March 31, 2014 with wind power; SPP met 33 percent of demand on April 6, 2013 with wind power; and, Xcel Energy Colorado met 60 percent of demand on May 2, 2013 with wind power. Operational and technical upgrades to the power system may be required to accommodate high levels of variable, non-dispatchable RE like wind and solar over longer time periods; however, the penetration levels cited above have been achieved without negative impacts to reliability due in large part to low-cost measures such as expanded operational flexibility and effective coordination with other regional markets.
RE can contribute to reliable system operation. The abundance and diversity of RE resources in the U.S. can support multiple combinations of RE in much higher penetrations. When California, the Midwest, PJM, New York, and New England experienced record winter demand and prices during the polar vortex, wind generation played a key role in maintaining system reliability.
Wind and solar PV are increasingly productive and capable of being accurately forecast, which improves grid reliability. Increasing capacity factors mean less variability and more generation. While the wind industry develops more projects at lower wind speed sites, wind turbine design changes are driving capacity factors higher among projects located in a given
New variable RE generators can provide more electrical power grid support services beyond just energy. Modern wind turbine power electronics allow turbines to provide voltage and reactive power control at all times. Wind plants meet a higher standard and far exceed the ability of conventional power plants to “ride-through” power system disturbances, which is essential for maintaining reliability when large conventional power plants break down. Xcel Energy sometimes uses its wind plants' exceedingly fast response to meet system need for frequency response and dispatchable resources. Utility-scale PV can incorporate control systems that enable solar PV to contribute to grid reliability and stability, such as voltage regulation, active power controls, ramp-rate controls, fault ride through, and frequency control. Solar generation is capable of providing many ancillary services that the grid needs but, like other generators, needs the proper market signals to trade energy generation for ancillary service provision.
The transmission network can connect distant high-quality RE to load centers and improve reliability by increasing system flexibility. Investments in transmission and distribution upgrades also enable improvements in system-wide environmental performance at lower cost.
The potential range of new transmission construction is within historical investment magnitudes. Under nearly all scenarios analyzed for the DOE's Quadrennial Energy Review, circuit-miles of transmission added through 2030 are roughly equal to those needed under the base case, and while those base case transmission needs are significant, they do not appear to exceed historical annual build rates. DOE's Wind Vision findings project 11.5 gigawatts of wind per year from 2021-2030. This deployment level would require 890 circuit miles per year of new transmission; 870 miles per year have been added on average between 1991 and 2013. 11.5 gigawatts per year is consistent with building block 3 deployment levels for wind capacity over the compliance period. DOE's SunShot scenario, which increases utility-scale PV to 180 gigawatts by 2030, required spending of $60 billion on transmission through 2050. On an average annual basis, this expenditure is within the historical range of annual transmission investments made by IOUs in recent decades.
Incremental grid infrastructure needs can be minimized by repurposing existing transmission resources. Transmission formerly used to deliver fossil-fired power to distant loads can—and is—being used to deliver REwithout new infrastructure. First Solar's Moapa project uses transmission built to deliver coal-fired power from Navajo to Los Angeles. NV Energy's retirement of Reid-Gardner will free up additional transmission capacity. The Milford wind projects in Utah already utilize transmission that was built to deliver coal power to Los Angeles.
Storage can be helpful but is not essential for the feasibility of RE deployment because there are many sources of flexibility on the grid. DOE's Wind Vision and many other studies have found an array of integration options (
Increasing regional coordination between balancing areas will increase operational flexibility. The Energy Imbalance Market (EIM) recently implemented by the California ISO and Pacificorp is a good example of the increased coordination that will be helpful in ensuring that resources across the West are being utilized in an efficient way.
Significant wind and solar supply chains have developed in the past decade to serve the fast-growing US RE market. For wind, domestic production capability would likely have to increase to accommodate projected builds under the CPP in the 2022-2030 time period; however, the global supply chain has expanded significantly to serve multiple markets and can augment production from the domestic supply chain, if necessary. At the start of 2014, the U.S. domestic supply chain could produce 10,000 blades (6.2 gigawatts) and 4300 towers (8 gigawatts) annually. It is not anticipated that expanded domestic manufacturing will be constrained by raw materials availability or manufacturing capability. For solar technologies, the global supply chain has a capacity that has significantly expanded over the past few years from 1.4 gigawatts per year in 2004 to 22.5 gigawatts per year in 2011. Current capacity exceeds these levels and is expected to grow. For PV systems, raw materials like tellurium and indium are at highest risk of supply shortage, but these materials are not used in the PV technologies currently being deployed at large-scale.
The EPA believes that RE generation at the levels represented in building block 3 can be achieved at reasonable costs. In the EPA's modeling of the building block 3 generation level, the projected cost of achieving CO
In this section, the EPA sets out subcategory-specific CO
These performance rates reflect the average emission rate requirement for each subcategory. Similar to the proposal, they are presented as adjusted average emission rates that reflect other generation components of BSER (
The performance rates are expressed in the form of adjusted
The EPA is finalizing the performance rates in a manner consistent with the proposal, with appropriate adjustments based on comments. Stakeholders had the opportunity to demonstrate during the comment period that application of one or more of the building blocks would not be expected to produce the level of emission reduction quantified by the EPA because implementation of the building block at the levels envisioned by the EPA was technically infeasible, or because the costs of doing so were significantly higher than projected by the EPA. The EPA has considered all of this input in setting final performance rates.
The remainder of this section addresses two sets of topics. First, we discuss several issues related to the form of the performance rates. Second, we describe the performance rates, computation procedure, and adjustments made between proposal and final based on stakeholder feedback in the comment period.
Some of the topics addressed in this section are addressed in greater detail in supplemental documents available in the docket for this rulemaking, including the CO
The EPA has developed a single performance rate requirement for existing fossil steam units in the contiguous U.S., and a single rate for existing gas turbines in the contiguous U.S., reflecting application of the BSER, based on all three building blocks described earlier, to pertinent data. The rates are intended to represent CO
The emission performance rates are set forth in Table 11 below, followed by
The emission performance rates are expressed as adjusted output-weighted-average emission rates for each subcategory. As discussed later in this section, the emission rate computation includes an adjustment designed to reflect mass emission reductions associated with lower-emitting BSER components. The adjustment is made by estimating the annual net generation associated with an achievable amount of qualifying incremental lower-carbon and zero-carbon generation and substituting those MWhs for the baseline electricity generation and CO
Some commenters suggested that the interim period starting in 2020 provided too little time for implementation of measures required to demonstrate compliance during the interim period. As discussed in section V.A.3.g of this preamble, the EPA has determined that an interim period beginning in 2022 provides sufficient time for states to undertake necessary planning exercises and for the implementation of measures towards achieving the performance rates. The EPA determined the interim rates in a manner similar to proposal, with an adaptation to address the revised timing of the interim compliance period (beginning in 2022 rather than in 2020 as proposed). They reflect the averaging of estimated emission performance rates for each year in the interim period (
The interim performance rates are less stringent than the final 2030 emission performance rates because the amount of emission reduction potential identified for the BSER increases over time, as explained in section V.
The interim and final emission performance rates for fossil steam and NGCC units are presented in the form of adjusted output-weighted-average CO
a.
First, the EPA sets an emission rate requirement for each subcategory by identifying the technology-specific reductions available under the building blocks. We then give each state the choice to apply the emission performance rates directly to the affected EGUs within the state or provides the opportunity to use the statewide rate-based goal or the equivalent mass-based form translated from the emission performance rates for state plan purposes. The emission performance rates reflect the BSER, and the statewide rate-based goal and statewide mass-based goal are alternative metrics for realizing the emission performance rates at the aggregate affected fleet level for a state.
Stakeholders have expressed support for having the flexibility to choose from among the multiple options for crafting an implementation plan to realize the BSER. The EPA is providing emission performance rate-based guidelines that apply uniformly to technology subcategories nationwide, and the EPA is providing corresponding state emission rate goals and state mass goals to further enhance compliance flexibility for each state. This approach allows each state to adopt a plan that it considers optimal and is consistent with the state flexibility principle that is central to the EPA's development of this program.
b.
The second aspect noted above concerns the expression of the goals in terms of net energy output
c.
This final rule provides an expression of the BSER as subcategory-specific emission performance rates rather than the state goals provided at proposal. Whereas the proposal also estimated the BSER impact on fossil steam and NGCC emissions and generation, it went one step further by averaging these two technology rates into a single rate for each state. Under this final rule, the EPA is identifying the fossil steam rate and the NGCC rate separately instead of only presenting them in a blended fashion at the state level.
The modification from a blended emission rate in the proposed rule to a subcategory-specific emission performance rate for affected EGU categories in the final rule was made in response to comments that technology
The EPA's main consideration has been to ensure that the expression of the BSER reflects opportunities to manage CO
d.
Section V above discusses the severability of the three building blocks upon which the CO
The methodology used to compute the performance rates is summarized on a step-by-step basis below in section 3. The methodology is described in more detail in the CO
In order to calculate the subcategory-specific emission performance rates reflecting the BSER, the EPA first needed to develop a baseline inventory of likely affected EGUs in order to estimate the impact of the BSER. The EPA developed an inventory of likely affected units that were operating in 2012 or that began construction prior to January 8, 2014 and that appeared to meet the final rule's applicability criteria.
Since the final rule's applicability includes under construction units, the EPA also identified units that had not yet commenced operation by the 2012 baseline period, but that commenced construction before January 8, 2014. The EPA received significant comment on the proposal's sole use of the National Electric Energy Data System (NEEDS) to identify these under construction units. Commenters suggested that the EPA also utilize EIA and 2012 proposed unit-level files to help better identify under construction units. In some cases, NEEDS did not reflect units that had commenced construction. Therefore, the EPA updated its approach to identifying units that had commenced construction prior to January 8, 2014, but that had not commenced operation in 2012. In the final rule, the EPA uses EIA data, comments, as well as NEEDS data to identify these under construction units.
These units that were operating by 2012 along with those that had not commenced operation by 2012 but had commenced construction by January 8, 2014, reflect the EPA baseline inventory of likely affected EGUs. The CO
The EPA received significant comment that units that came online during the baseline year (
In the proposed rule, the EPA considered using a historical-year data set or a projected-year data set as a starting point for applying the technology assumptions identified under BSER. The EPA proposed using 2012 data as it was the most recent data year for which complete data were available when the EPA undertook analysis for the proposed rule and it reflected actual performance at the state level. The EPA took comment on alternative data sets. In particular, the EPA issued a NODA on October 30, 2014 (79 FR 64543) in which we provided 2010 and 2011 historic data for consideration.
The EPA received a significant number of comments supporting the use of historical data as the basis from which to quantify performance rates reflecting BSER. Some commenters supported the 2012 data year as the best reflection of the power fleet, and some suggested that the EPA use a different year or a historical average to control for data anomalies in 2012. Moreover, some commenters pointed out that using 2010, 2011, 2012 data, or an average of the three would not address their concerns about recent year anomalies in hydro generation due to high snow pack. Some commenters also suggested the EPA use a baseline including years prior to 2012, not to increase representativeness of the power sector, but as a means of recognizing early action.
In this final rule, the EPA is taking an approach to the baseline year where we still largely rely on reported 2012 data as the best and most recent available data representing the power sector from which to apply the BSER, but also including targeted baseline adjustments to address commenter concerns with 2012 data.
Some commenters supported the EPA's use of 2012 data to inform performance rates, and the EPA agrees that 2012 data with targeted adjustments, relative to other historical years, best reflects the power sector and best informs the performance rates that pertain to the BSER. The EPA believes that starting with 2012 data is more accurate and better informs the BSER than an earlier historical year or historical multi-year average for the following reasons:
(1) Of the historical data fully available at the time the proposal analysis began, 2012 was the most recent and best reflects the power fleet. Approximately 43 GW of new capacity came online in 2010 and 2011. In other words, there was 43 GW of capacity online as of 2012 that had not been in service at some point during the 2010-2011 period. Likewise, approximately 17 GW of capacity that were operable in 2010 and/or 2011 were retired prior to 2012.
(2) A three-year baseline would not address some of the substantive concerns raised by commenters. Many commenters pointed out that using a three-year baseline would not address their critical concern about variation in the hydrological cycle due to snow pack (particularly in the Northwest), because the snow pack was significantly above average in both 2011 and 2012. The EPA agrees with commenters that we can better address their baseline data concerns regarding an average hydro year by identifying those states with a significant share of hydro generation and variation in that hydro generation, and making targeted adjustments to those states' affected fossil generation levels in order to reflect a more typical snow-pack year. This procedure is described in more detail below and in theTSDs.
(3) In addition to being, in the EPA's view, a less representative baseline of the existing power fleet, a multi-year baseline would also likely entail complexity when determining how to average together yearly fleet data while appropriately accounting for fleet changes occurring during those years. The 2012 baseline starting point maximizes the EPA's reliance on latest reported operating data and minimizes the need for fleet capacity adjustments. For instance, because of year-to-year fleet turnover, the averaging of multiple baseline years would require additional assumptions in regards to which generation to consider from a fleet that is changing in a given state or region (or even where units are switching fuel sources such as a coal-to-gas conversion).
(4) Due to the region-based approach to quantify building blocks and the BSER as subcategory-specific emission performance rates, variations in unit-level data do not significantly impact the calculation of emission performance rates. For instance, if one fossil unit is operating less in a given year due to an outage, another fossil unit in the same region is generally operating more. Therefore, at the regional level, fossil generation and emissions do not vary to the same degree that unit-level data varies. Moreover, the variation at the regional level that does exist in 2012 relative to previous years is not necessarily unrepresentative variation, but illustrates trends in the power sector infrastructure that are desirable to capture for purposes of determining a representative year from which further improvements in CO
(5) Some commenters suggested the EPA use an earlier baseline year as a means of recognizing early action. They noted that an earlier baseline would reflect a higher-emitting fleet and therefore when the same level of building block MWhs are applied, they would result in a higher (
(6) Some commenters pointed out that the EPA relied on multi-year historical data in allowance allocation in previous rulemakings (
(7) The EPA received significant comment that 2012 was not a representative year for natural gas prices, and thus the EPA should use another year. The EPA disagrees with this comment, and does not view it as grounds for a change to the baseline period. While the EPA does recognize that Henry
In summary, the EPA believes that continuing to rely on 2012 data while incorporating select data adjustments as detailed below is not only a reasonable choice and adequately supported, but a more reliable and preferable starting point for determining the BSER requirements.
The EPA made corrections to unit-level 2012 data based on commenter feedback. In addition, we also made some adjustments to 2012 data, not to address a correction, but to address a concern about the representativeness of the data. Although the EPA determined that the 2012 data year better informed its BSER determination than a preceding year or a multi-year average, commenters did identify some limitations that we are addressing through targeted adjustments. These are discussed below:
(1) Adjustments to state-level data to account for annual variation in the hydrologic cycle as it relates to fossil generation.
Hydropower plays a unique role in a handful of states in that (1) it is a significant portion of their generation portfolio, (2) it varies on an annual basis, and (3) 2012 was an outlier year for snow-pack (meaning hydropower was above and fossil generation was below its historical average).The EPA notes that these three conditions are not present in other weather-based RE technologies like solar or wind.
Unlike market conditions (
(2) Extended unit outages due to maintenance.
Generally, because of the regional-level approach to calculate performance rates, the EPA does not believe that unit-level variations in operation influence the subcategory-specific performance rates reflecting BSER. For instance, as some units ramp down, and others ramp up to replace their load at the regional level, total fossil generation changes little due to these fossil-for-fossil substitutions. Unit-level variation does not inherently entail region-wide variation.
However, the EPA did receive comment that in limited cases, this could have a substantial impact on an individual state if it chooses to use a rate-based or mass-based statewide goal. Even though the EPA is calculating subcategory-specific performance rates that it believes are not affected by this type of unit-level variation, it still evaluated the possible impacts it may have when converting to state goals in the next section. The EPA examined units nationwide with 2012 outages to determine where an individual unit-level outage might yield a significant difference in state goal computation. When applying this test to all of the units informing the computation of the BSER, emission performance rates, and statewide goals, the EPA determined that the only unit with a 2012 outage that (1) decreased its output relative to preceding and subsequent years by 75 percent or more (signifying an outage), and (2) could potentially impact the state's goal as it constituted more than 10 percent of the state's generation was the Sherburne County Unit 3 in Minnesota. The EPA therefore adjusted this state's baseline coal steam generation upwards to reflect a more representative year for the state in which this 900 MW unit operates.
(3) Many commenters also noted that because the EPA uses annual data, 2012 was not representative for units coming online part way through the year. The EPA relies on annual data, so if a unit is underrepresented in a certain part of the year because it is not yet online, then another unit is likely over-represented as it is operating more than it otherwise would when the second unit commences operation. Therefore, the resulting state-level and regional-level aggregate annual generation level used in determining the BSER may be considered to be representative and there is not necessarily a need for any adjustment.
However, the EPA recognizes that the over-represented and under-represented units do not necessarily fall within the same state, and therefore this potential difference in the state location of the affected units could have an impact when estimating appropriate statewide goals. To address this comment, the EPA adjusted the 2012 generation data for fossil units coming online during 2012 to a more representative annual operating level for that type of unit reflecting its incremental impact on generation and emissions. This effectively resulted in increased baseline emissions and generation assumed for those units beyond their reported partial-year operations in 2012. Conceptually, the assumption of full-year operation at units that came online partway through 2012 could pair with an assumed reduction in the operation of other units somewhere in the same region. However, the EPA made no corresponding deduction to represent this likely decreased utilization at other affected units because it was impossible to project the state location of such units with certainty and the assumed utilization level was meant to reflect the incremental impact on the baseline. As a result, this data adjustment increases the total generation and emissions for units reporting in the 2012 baseline beyond the 2012 reported levels.
Additionally, as done in proposal, the EPA continued to identify under construction units that did not begin operation in 2012, but had commenced construction prior to January 8, 2014 and would commence operation sometime after 2012. As described in the next section, the EPA estimated baseline generation and emissions for these units as they had no 2012 reported data.
In summary, this final rule continues to rely on the latest reported 2012 data as the foundation for quantifying the BSER. However, the EPA has made limited adjustments, in addition to corrections identified by commenters, to the 2012 data to address some of the relevant concerns raised by commenters. Therefore, the baseline is informed by 2012 data, but not limited to 2012 data.
In this section we describe how we develop the equations used to determine the emission performance rates for fossil steam and NGCC units that express and implement BSER. More detailed
When developing equations to implement BSER, we adhere to a number of basic principles. First, we ensure that the equations are consistent with the BSER itself, and in particular, reflect the redistribution of generation among fossil steam, NGCC and renewables embodied in building blocks 2 and 3. In doing this, we account for the interactions between building blocks in a way that is consistent with the assessment of incremental building block generation potential and the compliance framework for Emission Reduction Credits (ERCs). In particular, we must ensure that each increment of building block 3 emission reduction potential is applied to either fossil steam or NGCC units but not both. The equations we develop must also take account of the dual status of existing NGCC units, which are simultaneously affected units and provide generation that is an element of the BSER itself.
In addition, we are applying the BSER, as we have done in calculating other section 111(d) standards, to a defined population of existing affected sources, represented in this case by the generation of the source category in the 2012 adjusted baseline. This provides an empirical historical baseline against which we define the performance rates and their state goal equivalents. In doing so, we must account for any offsetting increases in emissions that result from applying the BSER control measures, as we have done in setting other standards. For example, when determining BSER for particulate matter control, a number of pollution control devices (such as sorbent injection technologies) themselves create particulate matter. If the particulate matter created by these control devices were not appropriately accounted for when developing the standard intended to address the primary emissions of particulate, this could create an unreasonably stringent PM standard. In the current context, this means recognizing that increasing NGCC capacity utilization in accordance with building block 2 both offsets higher emitting steam generation and increases emissions at the NGCC units themselves, which are also affected entities that must demonstrate compliance with the BSER. Thus, it is essential that we apply the building blocks in a way that avoids creating a level of stringency in the performance standards for affected EGUs that goes beyond what we have determined to be the BSER—while at the same time ensuring that equations apply the building blocks to generate performance standards that represent the full application of the BSER to the affected EGUs.
Under section 111, the EPA adopts emission performance standards that are based on the BSER. The emission performance rates reflect our recognition of the value of giving sources the flexibility to adopt equivalent emissions reduction strategies and measures that for them may be preferable (in a specific circumstance) to the technologies and measures that we define as the BSER. An important function of the emission performance rates representing the BSER is to provide the flexibility needed to allow alternative compliance options, including the development of new technologies or the deployment of effective technologies outside of the BSER technologies. In the guidelines we issued under section 111(d) for landfill gas, for example, we adopted the primary standard based on flaring of any captured landfill gas, but we also developed equations that led to an expression of the BSER that allowed for the alternative of capturing the gas and combusting it in an electrical generating unit.
Finally, in deriving the emission performance rates, there are a number of considerations we took into account. First, it is important that the baseline from which the rates are derived be transparent and based on observable, historical data. Second, the emission performance rates must reflect the emission reductions achievable through the best system of emission reduction. Because the BSER includes shifting of emissions from higher-emitting to lower-emitting sources, state compliance frameworks will likely involve a combination of physical measures at the plant (where either rate or generation may be reduced) and some form of credit for lower-emitting generation (or demand side measures) outside of the plant. In this context, the emission performance rates must provide appropriate incentives for affected entities to achieve the emission reductions encompassed in the BSER, including through state plans that provide crediting for lower-emitting generation. Third, and as set forth below, we must account for the EPA's determination that pro rata implementation of building block 3 is the best reflection of the potential for RE to displace both fossil steam and NGCC, and the dual role of NGCC units as both affected sources and a BSER compliance technology.
This set of considerations was central to the development of the BSER equations that the EPA describes next. They were particularly important for steps five through seven below which address building blocks 2 and 3, building blocks that have both significant overlap with each other and which impact steam and NGCC units in an integrated way.
Step one (compilation of baseline data). On a unit-level basis, the EPA obtained total annual quantities of CO
For the under construction units (
The estimated emissions and generation for under construction units were added to the 2012 reported emissions and generation data for the affected units that had already commenced operation prior to 2012 to derive an adjusted historical baseline total for each state that was reflective of all likely affected 111(d) sources.
Step two (aggregation to the regional level). The EPA took comment on applying building blocks at the regional level, and received significant comment supporting such an approach. Therefore, whereas the proposal aggregated the baseline data to the state level, the final rule further aggregated it to the regional level prior to building block application. The regions reflect the Eastern, Western, and Texas Interconnections. The shift to a regional framework was based on comments suggesting that the EPA would better capture the interstate impacts of the building blocks and reflect the interconnected nature of the electric grid under a regional structure. The basis for the regions is defined and discussed in Section V.A.3.
Step three (identification of source category baseline emission rates). As discussed in the beginning of this section, the EPA took a technology-specific approach to quantifying guidelines. Therefore, whereas the proposal first averaged the fossil steam rate and NGCC rate together before applying the building blocks and defining state goals, the final rule applied the building blocks at the regional level to give a separate fossil steam rate and NGCC rate for each region. The starting point for calculating the subcategory-specific emission performance rates was the baseline regional emission rates for both fossil steam and NGCC in the year 2012 with the modifications discussed above.
Step four (application of building block 1). The baseline CO
Step five (application of building block 3). At proposal, the EPA incorporated incremental RE MWhs (where incremental means the amount above the adjusted 2012 baseline) by adding them to the denominator of the emission rate goal. In response to comments on this approach, the EPA issued a NODA discussing an alternative methodology of incorporating building block 3 in a manner more analogous to building block 2 treatment, where the incremental MWhs identified for the building block replace baseline fossil MWhs on a one-to-one basis. The EPA is adopting this replacement methodology for building block 3 in the final rule consistent with comments noting that such a computational procedure better reflects the reduction potential of that building block.
Under this methodology, all of building block 2 incremental NGCC potential and part of building block 3 incremental RE potential were ultimately applied to replace higher-emitting fossil steam generation and emissions, while the remaining building block 3 potential was applied to replace NGCC generation and emissions. Commenters noted that under this approach building block 3 should be applied first, or the EPA would understate the potential of building block 2 by subtracting out some NGCC generation after the 75 percent utilization level of NGCC had been applied to replace fossil steam. The EPA agrees and calculated the building block 3 impacts first in developing the emission performance rates.
To implement this, first, building block 3 replacement potential was identified for each region to arrive at a total amount of incremental zero-
Step six (application of building block 2). If the remaining generation level for the NGCC fleet in a region, taking into account the previous step's replacement of NGCC generation, was less than 75 percent of the fleet's potential summertime generating capacity (the potential capacity factor the EPA determined to represent the BSER), then the NGCC generation in the region was assumed to increase to levels equal to the lesser of (1) its potential at a 75 percent capacity factor
Step seven (accounting for and facilitating the emission reductions achievable through the implementation of the best system of emission reduction).
This step quantifies the aggregate emission changes associated with the emission rate improvement and generation replacement patterns described in steps four, five, and six to arrive at an adjusted fossil steam emission rate and an adjusted NGCC emission rate for each region that will, as discussed above, (1) enable the implementation of all three building blocks, (2) be based on observable, concrete baselines, and (3) reflect the BSER.
First, in developing the emission performance rates, the EPA had to answer the question of how to reflect the building blocks in the equations defining the rates in a manner that would enable the generation shifts that are essential components of the BSER. In the case of building block 3, the EPA accomplished this by incorporating the pro rata share of incremental (above baseline) zero emitting generation into the emission rates for each group of affected EGUs, thus ensuring that these EGUs would have to include a corresponding amount of zero-emitting generation in their compliance calculations, either through the acquisition of credits or through some other mechanism as determined by their state in its implementation plan.
For building block 2, a similar mechanism is needed. Accordingly, a portion of the NGCC generation and emissions used to replace fossil steam must be averaged into the steam rate, analogous to what was done with building block 3. The EPA considered two approaches to define the quantity of NGCC generation and emissions to be averaged into the steam rate: (1) Incremental NGCC generation after the implementation of building block 3 and (2) incremental NGCC generation from baseline levels. For the reasons below, the EPA has determined that the second approach better reflects the considerations discussed above.
As discussed above, it is beneficial that the baseline from which emission performance rates are derived be transparent and based on observable historical data. The first approach, however, depends on the level of incremental NGCC generation relative to what is available after the implementation of building block 3. This level of NGCC generation (obtained after replacing baseline levels of generation with NGCC's pro rata share of incremental RE generation) only exists as an intermediate step in the BSER calculation. It is not based on an observable or concrete level of generation.
In Section VIII we discuss methods for creating ERCs for implementing shifting of generation from steam to NGCC, and this discussion illustrates the value of relying on an observable and concrete baseline. In that section we suggest that incentivizing and facilitating the purchase of ERCs as a compliance option for steam units could be implemented through the use of a factor that creates a fraction of an allowable credit for each hour that an NGCC operates. This factor is derived from the incremental generation of NGCC post-building block 2, relative to the baseline. While a different factor could be derived from the hypothetical intermediate level resulting from the pro rata application of zero emitting generation to NGCC in building block 3 (by transferring the full amount of NGCC emissions and generation replacing steam generation in building block 2), the EPA believes that grounding baselines in historical data (such as those used to derive the 2012 baseline) is both more transparent and easier to understand in a way that is more useful to states and utilities, in contrast to the practical challenges of relying on a calculated level that corresponds to an interim step within the emission performance rate calculation. As long as the crediting framework for creating ERCs is consistent with the amount of gas emissions and generation that is transferred to the coal rate, either the chosen option or the option of transferring the entire quantity of gas emissions and generation that occurred in step six to the coal rate would provide an incentive for the power market to implement the shift in generation from coal to gas.
Also as discussed above, it is important that the compliance equations reflect the BSER pro rata allocation of RE to fossil steam and NGCC generation. The first approach to define the quantity of NGCC generation and emission to be averaged into the steam rate would require the steam rate to take into account the total additional NGCC generation that results from the application of building block 3 before building block 2 has been applied. This approach would reflect in the compliance rate for steam units a greater share of the implementation of building block 3. Ensuring that emission performance rates for both steam and gas units reflect the emission reduction potential of building block 3 is integral to the building block 3 methodology and also recognizes that application of building block 3 on a pro-rata basis was intended to achieve emission reductions from both NGCC and fossil steam commensurate with their emissions reduction opportunities.
If the EPA were to use the increment of NGCC emissions and generation derived at the intermediary step after the application of building block 3, rather than the increment relative to the 2012 baseline, the effect would be to largely assign to fossil steam the building block 3 generation shift apportioned to NGCC. That, in turn, would have undermined the fact that building block 3 was determined to be a BSER measure applicable to the entire source category, comprising NGCC as well as fossil steam, and would have conflicted with the preceding steps we are taking to develop the equations. Instead, by using only the incremental NGCC generation relative to the baseline, the EPA has ensured that the logic behind the pro rata displacement of fossil generation by RE generation is reflected in the emission rates. Having established the appropriate way to measure the amount of incremental gas generation placed in the fossil steam rate, the EPA is able to calculate the subcategory-specific emission performance rates. For the numerator of the fossil steam rate, the EPA multiplied the remaining fossil steam generation (post-step six) by the fossil steam rate reflecting the heat rate improvement from building block 1 (step four). We then added in the emissions associated with the incremental NGCC generation from step six by multiplying the incremental NGCC generation as discussed above (difference between the baseline NGCC generation level and post-step six NGCC generation) by the baseline NGCC rate for that region.
For the fossil steam denominator, the EPA added the remaining fossil steam generation (post-step six), the incremental NGCC generation defined above, and the amount of zero emitting building block 3 MWhs apportioned to fossil steam generation in the region (step five). Dividing the fossil steam numerator described above by this fossil steam denominator resulted in a regional adjusted fossil steam rate reflecting the three building blocks.
For the NGCC performance rate, the EPA calculated a numerator in a similar manner. First, we took the remaining NGCC generation (post step six) and multiplied it by the regional baseline NGCC rate to calculate the total emissions in the numerator. For the denominator, the EPA added the remaining NGCC generation (post step six) to the amount of zero-emitting building block 3 generation assigned to that technology in step five. Dividing the emissions by this total generation value (inclusive of the RE generation apportioned to NGCC) provided a regional adjusted NGCC rate.
Step eight (determining the nationwide subcategory-specific emission performance rate).
Following step seven, we evaluated the resulting adjusted fossil steam rates and NGCC rates for each region and identified the highest (least stringent) emission rate among the three regions for each technology category. This becomes the nationwide emission performance rate for that technology class. This ensures that the same rates are applied to facilities in each region and that these rates are achievable by facilities in all three regions.
Finally, the EPA repeated steps four through eight for each year 2022-2030.
It bears emphasis that the procedure described above was used only to determine emission performance rates, and the particular data inputs used in the procedure are not intended to represent specific requirements that would apply to any individual EGU or to the collection of EGUs in any state. The specific requirements applicable to individual EGUs, to the EGUs in a given state collectively, or to other affected entities in the state, would be based on the emission standards established through that state's plan. The details of how states could demonstrate compliance with the emission performance rates or statewide goals through different state plan approaches that recognize emission reductions achieved through all the building blocks are discussed further in section VIII on state plans.
Finally, the procedures and assumptions in the equation to calculate emission performance rates are not intended to reflect a compliance scenario in a future year, but rather reflect a representative year in which the building blocks are applied. The power sector fleet will continue to turn over, and in some cases has already experienced turnover beyond the baseline period. However, while the system's fleet may change, the EPA believes this turnover will only further promote the feasibility of the emission performance rates. Fleet turnover has trended towards, and is expected to continue to trend towards, lower-emitting generation sources that will make reductions more readily available.
In section VI of this preamble, the EPA provides the methodology for computing subcategory-specific CO
The EPA is reconstituting the emission performance rates discussed in section VI into statewide CO
In the June 2014 proposal, the EPA proposed a set of state-specific emission rate-based CO
Numerous commenters encouraged and supported the EPA's efforts to allow states the maximum possible degree of flexibility in developing plans for their affected EGUs, either as a mass-based or rate-based CO
Based on the comments received, the EPA is providing a straightforward translation methodology from the CO
CAA section 111(d) requires states to submit a plan that establishes standards of performance for affected EGUs that implement the BSER. States meet the statutory requirements of CAA section 111(d) and the requirements of the final emission guidelines by submitting emission standards for affected EGUs that meet the performance rates, which reflect the application of the BSER as determined by the EPA. Therefore, as a first step for states that choose to submit plans that meet the rate-based or mass-based goals, the goals must be determined to have equivalence as an application of the BSER. For the rate-based and mass-based state goals provided here, this equivalence is evident in the mathematical derivation of the goals, as is described in sections VII.B and VII.C below.
Further (as described in section VIII.J), the state plan must demonstrate that it has measures in place to ensure that any alternative to the performance rates (
Specifically, the EPA has determined that the three building blocks are the BSER, including shifting generation from an affected EGU to a lower-emitting affected EGU or to a non-
Since the two subcategory-specific emission performance rates represent the BSER, states that established standards of performance at or below those rates, by definition, would be implementing state plans that created no risk that affected EGUs would shift generation to new fossil-fired EGUs to an extent that would deviate from the BSER. Similarly, the EPA has determined that states using rate-based goals as the foundation for plans implementing the BSER are unlikely to foster generation shifts to new fossil fuel-fired sources to an extent that would deviate from the BSER. In contrast, however, EPA analysis has identified a concern that a mass-based state plan that failed to include appropriate measures to address leakage could result in failure to achieve emission performance levels consistent with the BSER.
In order to provide states flexibility for planning purposes, the EPA is providing a state-specific averaging of the subcategory-specific emission performance rates to determine a statewide goal. While the emission performance rates reflect the quantification of performance based on the BSER and embody the reductions estimated under building blocks 1, 2, and 3, the state goals reflect an equivalent approach through which states may choose to adopt and implement those subcategory-specific performance rates.
The EPA quantified the potential reductions of the BSER in the subcategory-specific emission performance rates established in section VI. These rates themselves reflect the reduction potential expected in emission rates under the BSER for each year from 2022 to 2030. To establish state goals, the EPA applied these rates to the baseline generation levels to estimate the affected fleet emission rate that would occur if all affected EGUs in the fleet met the subcategory-specific rates. This step respects the flexibility of sources to meet the rates in any manner that they see fit (
This step is repeated for each year from 2022-2029 using the emission performance rates calculated for each of those years in the previous section. The EPA also repeats this step for the interim state goal using the interim subcategory rates. The EPA then averages together the annual amounts in increments of 3 years, 3 years, and 2 years for 2022-2024, 2025-2027, and 2028-2029 to estimate emission rate averages for those periods that can provide one illustrative pathway for states to consider in meeting their interim goals. These 3- and 2-year increment are not regulatory guidelines or equivalents for interim goals, but rather benchmarks for demonstrating plan performance as discussed in Section VIII.F illustrative of a potential gradual reduction compliance strategy that states may use to reach their interim and final state goals.
As described in the steps above, the statewide goals represent an equivalent arithmetic combination of the subcategory-specific emission performance rates, weighted by the historical baseline generation levels upon which the BSER is premised. In particular, as discussed above, the method for deriving these goals assures equivalent flexibility by applying the CO
The EPA is also establishing mass-based statewide CO
The starting place for quantifying mass-based statewide CO
However, under a rate-based state plan, all affected EGUs have the opportunity to increase utilization, provided that sufficient emission reduction measures are available to maintain the necessary ratio of emissions to generation as quantified by the subcategory-specific emission performance rates. Due to the nature of the emission performance rate methodology, which selects the highest of the three interconnection-based values for each source category as the CO
The mass goals for existing sources are presented in Table 13. Although their derivation is equivalent to the subcategory-specific emission performance rates, in order to maintain this equivalence in the establishment of emission standards in state plans mass goals must be implemented in combination with requirements that align the incentives provided to affected and unaffected EGUs, specifically in order to prevent leakage.
As described in section VI, the subcategory-specific emission performance rates reflect the BSER as determined by the EPA. This final rule allows states to establish emission standards that meet either rate-based or mass-based state goals. As stated above, rate-based state goals were published in the proposed rule, and commenters not only supported having the flexibility to use rate-based goals or mass-based goals as part of state plans, but also requested that the EPA include mass-based goals in this final rule. But to ensure the equivalence of mass-based state goals, we must consider how the form of the goal affects its implementation and how the incentives it provides to affected EGUs on the interstate grid affect whether or not the BSER is fully implemented.
Because of the integrated nature of the utility power sector, the form of the emission performance requirements for existing sources may ultimately impact the relative incentives to generate and emit at affected EGUs as opposed to shifting generation to new sources, with potential implications for whether a given set of standards of performance is, at a minimum, consistent with the BSER, in the context of overall emissions from the sector. In this context, we, again, define as “leakage” the potential of an alternative form of implementation of the BSER (
However, leakage, where shifts in generation to unaffected fossil fuel-fired sources result in increased emissions, relative to what would have happened
This section specifically addresses the need for state plans designed to achieve either rate- or mass-based state goals to ensure that their plans succeed in implementing standards of performance that reflect the BSER by minimizing the difference in incentives provided to affected EGUs and new sources to generate in order to maintain equivalent emission performance with the CO
Rate-based goals do not in our view implicate leakage to an extent that would negate or limit the implementation of the BSER because under a rate-based state goal, similar to the subcategory-specific emission performance rates, existing lower-emitting affected EGUs, primarily NGCC units, are incentivized to increase their utilization in order to improve the average emission rates of affected EGUs overall. New units that are not subject to the rate-based state goal, and that are not an allowable measure for adjusting an EGU's CO
Mass-based goals for existing sources, however, incur a leakage risk to the extent that they incent generation shifts from affected EGUs to unaffected fossil fuel-fired sources in a way that negates the reliance on the BSER. In contrast to various forms of rate-based implementation, mass-based implementation in a state plan can unintentionally incentivize increased generation from unaffected new EGUs as a substitute action for reducing emissions at units subject to the existing source mass goal in ways that would negate the implementation of the BSER and would result in increased emissions. This occurs because, unlike in a rate-based system where rate-based averaging lowers the cost of generation from existing NGCC units relative to generation from new NGCC units, in a mass-based system the allowance price increases the cost of generation from existing NGCC units relative to generation from new NGCC units. The extent to which electricity providers opt to rely on this increase in unaffected new source utilization as a substitute for improving the emissions performance across existing sources would be fundamentally inconsistent with relying on the BSER to reduce emissions as the basis of the subcategory-specific emission performance rates.
As a result, notwithstanding the fact that mass goals for existing sources are quantified in a way that is an equivalent expression of the BSER, the form of mass goals is only equivalent if leakage is satisfactorily addressed in the state plan's establishment of emission standards and implementation measures. The EPA is therefore requiring that states adopting a mass-based state plan include requirements that address leakage, or otherwise provide additional justification that leakage would not occur under the state's implementation of mass-based emission standards. This requirement enables states to establish standards of performance that meet a mass-based goal equivalent to the performance rates and therefore reflect the BSER, as required by section 111(d). The required demonstration and options for state plans to minimize leakage are discussed in detail in section VIII.J of this preamble.
Further supporting the need for this requirement, the EPA has evaluated the mass goals in concert with some of the options to minimize leakage described in that section. As mentioned above, the EPA analysis identified a concern regarding leakage in a mass-based approach, namely that the mass-based implementation without measures to address leakage produced higher generation from new NGCC units and lower emission performance when compared to a rate-based implementation. Further analysis where implementation of the mass-based goals was coupled with measures to address leakage produce utility power sector emissions performance that is similar to emissions performance under the rate goals.
The EPA notes that it is the emission performance rates in section VI that constitute the application of the BSER to the affected EGUs and serve as the chief regulatory requirement of this rulemaking. The statewide CO
This adjustment flexibility provision is based on comments received at proposal. For example, some
Rate-based statewide CO
Alaska, Hawaii, Guam, and Puerto Rico constitute a small set of states and U.S. territories representing about one percent of total U.S. EGU GHG emissions. Based on the current record, the EPA does not possess all of the information or the analytic tools needed to quantify the application of the BSER for these states and territories, particularly data regarding RE costs and performance characteristics needed for building block 3 of the BSER. The NREL data for RE that the EPA is relying upon for building block 3 does not cover the non-contiguous states and territories.
The EPA acknowledges that NREL has collaborated with the state of Hawaii to provide technical expertise in support of the state's aggressive goals for clean energy, including analyses of the grid integration and transmission of solar and wind resources.
Because of the lack of suitable data and analytic tools needed to develop area-appropriate building block targets as defined in section V, the EPA is not setting CO
The EPA recognizes, however, that EGUs in Alaska, Hawaii, Puerto Rico, and Guam emit CO
The agency intends to continue to consider these issues and determine what the appropriate BSER is for these areas. As part of that effort, the agency will investigate sources of information and types of analysis appropriate to devise the appropriate levels for building block 3 and BSER performance levels. Because we recognize that these areas face some of the most urgent climate change challenges, severe public health problems from air pollution and some of the highest electricity rates in the U.S., the EPA is committed to obtaining the right information to quantify the emission reductions that are achievable in these four areas and putting goals in place soon.
After the EPA establishes the emission guidelines that set forth the BSER, each state with one or more affected EGUs
The next few paragraphs present an overview of the main features of the final emission guidelines, highlighting key changes from proposal. In the rest of this section, we describe in detail the various elements of the final emission guidelines' requirements for state plans.
The proposal contained rate-based goals for each state, reflecting a blended reduction target for that state's fossil fired EGUs, and provided that states could either meet that rate-based goal or convert it to a mass-based equivalent goal. Reflecting the final BSER described in section V and in response to many comments desirous that the EPA establish mass-based goals in the final rule, these final guidelines include three approaches that states may adopt for purposes of implementing the BSER, any one of which a state may use in its plan. These are: (1) Establishing standards of performance that apply the subcategory-specific CO
In the proposal, we provided two designs for state plans: One where all the reduction obligations are placed directly on the affected EGUs and one, which we called the “portfolio approach,” that could include measures to be implemented, in whole or in part, by parties other than the affected EGUs. In the final guidelines, we retain that
States that choose an emission standards plan may establish as standards of performance for their affected EGUs the subcategory-specific CO
In the proposal, we proposed that states could use the portfolio approach to meet either a rate- or mass-based goal. In these final emission guidelines, the state measures approach is available only for a state choosing a mass-based CO
The final guidelines reflect the changes to the timing of the reductions within the interim period, which is laid out in section V as part of the determination of the BSER. States may adopt in their plans emission reduction trajectories different from the illustrative three-step trajectory included in these guidelines for purposes of creating a “glide path” between 2022 and 2029, provided that the interim and final CO
We recognize that while we are establishing 2022 as the date by which the period for mandatory reductions must start as part of our BSER determination, utilities and other parties are moving forward with projects that reduce emissions of CO
For all types of plans, the final guidelines make clear that states may adopt programs that allow trading among affected EGUs. The final guidelines retain the flexibility for states to do individual plans, or to join with other states in a multi-state plan. In addition, and in response to comments from many states and other stakeholders, the guidelines provide that states may design their programs so that they are “ready for interstate trading,” that is, that they contain features necessary and suitable for their affected EGUs to engage in trading with affected EGUs in other “trading ready” states without the need for formal arrangements between individual states.
We have been mindful of the concerns raised by stakeholders about reliability. The final BSER, especially the changes in the timing of the interim period, substantially address these concerns. The flexibilities provided for the design of state plans, including the ability to use trading programs, further enhance system reliability. We have included, as an additional assurance, a reliability safety valve for use where the built-in flexibilities are not sufficient to address an immediate, unexpected reliability situation.
The EPA believes that all the flexibilities provided in the final rule are not only appropriate, but will enhance the success of the program. CO
In developing the plan, the state rulemaking process must meet the minimum public participation requirements of the implementing regulations as applicable to these guidelines, including a public hearing and meaningful engagement with all members of the public, including vulnerable communities. In the community and environmental justice considerations section, section IX of this preamble, the EPA addresses the actions that the agency is taking to help ensure that vulnerable communities are not disproportionately impacted by this rule. These actions include conducting a proximity analysis, setting expectations for states to engage meaningfully with vulnerable communities and requiring that they describe their plans for doing so as they develop their state plans, providing communities with access to additional resources, providing communities with information on federal programs and resources available to them, recommending that states take a multi-pollutant planning approach that examines the potential impacts of co-pollutants on overburdened communities, and conducting an assessment to determine if any localized air quality impacts need to be further addressed. Additionally, the EPA outlines the continued engagement that it will be conducting with states and communities throughout the state plan development process.
As discussed in more detail in section VIII.E, commenters, particularly states, provided compelling information establishing that for some, and perhaps many, states it will take longer than the agency initially anticipated to develop and submit their required plans. In response to those comments, we are finalizing a plan submittal process that provides additional time for states that need it to submit a final plan submittal to the EPA after September 6, 2016. Within the time period specified in the emission guidelines (from as early as September 6, 2016, to as late as September 6, 2018, depending on whether the state receives an extension), the state must submit its final state plan to the EPA. The EPA then must determine whether to approve or disapprove the plan. If a state does not submit a plan, or if the EPA disapproves a state's plan, then the EPA has the express authority under CAA section 111(d) to establish a federal plan for the state.
This section is organized as follows. First, we discuss the timeline for state plan performance and provisions to encourage early action. Second, we describe the types of plans that states can submit. Third, we summarize the components of an approvable state plan submittal. Fourth, we address the process and timing for submittal of state plans and plan revisions. Fifth, we address plan implementation and achievement of CO
This section describes state plan requirements related to the timing of achieving the emission reductions required in the guidelines and the state plan performance periods. This section also describes the CEIP the EPA is establishing to encourage early investment in certain types of RE projects, as well as in demand-side EE projects implemented in low-income communities.
The final guidelines establish three types of performance periods: (1) A final deadline by which and after which affected EGUs must be in compliance with the final reduction requirements, (2) an interim period, and (3) within that interim period, three multi-year interim step periods. As discussed below and in section V, these performance periods are consistent with our determination of the BSER and are also responsive to the key comments we received on this aspect of the state plans.
A performance period is a period for which the final plan submittal must demonstrate that the required CO
As previously discussed, the EPA has determined that the BSER includes implementation of reduction measures over the period of 2022 through 2029, with final compliance by affected EGUs in 2030. Therefore, the final rule requires that interim CO
This relatively long period—first for planning, then for implementation and achievement of the interim and final CO
The timelines established in the final rule respond to the issues raised in numerous comments regarding the concept of the interim period, including comments supporting the flexibility afforded states in developing their plans and the timing necessary to meet the 2030 emission requirements. Some commenters supported beginning the interim goal plan period at 2020. Others stated that the investments necessary to meet the proposed interim emission performance goals beginning in 2020 are unachievable in that timeframe or would place too great a burden on affected EGUs, states, and ratepayers. Some suggested that the 2020 interim goal step should be eliminated in favor of later start dates, including 2022, 2025, or other years. Some commenters urged the EPA to establish phased interim steps creating a steady downward trajectory that allowed several years for each step, compatible with the “chunkiness” of utility planning processes. Yet other commenters provided input suggesting that states be allowed to establish their own set of emission performance steps during the interim plan performance period and thereby control their own emission reduction trajectory or “glide path” for achievement of the interim goal and the 2030 goal, or that the EPA not establish any interim standards at all. Commenters also noted that for some states, there was not a significant difference between the interim and final goal, and, therefore, no glide path for those states. As discussed in previous sections, based on this input and our final determination of the BSER, the EPA has adjusted the interim period to include 2022-2029, is establishing three interim performance periods creating a reasonable trajectory from 2022 to 2030, and is also retaining the flexibility for states to establish their own emission reduction trajectory during the interim period.
As noted, the EPA has determined that the period for mandated reductions should begin in 2022, instead of 2020 as we proposed, because of the substantial amount of comment and data we received indicating that states and utilities reasonably needed that additional time to take the steps necessary to start achieving reductions. In order to assure the EPA and the public that states are making progress in implementing the plan between the time of the state plan submittal and the beginning of the interim period, and as discussed in further detail in section VIII.D, the final rule requires that the state plan submittal include a timeline with all the programmatic plan milestone steps the state will take between the time of the state plan submittal and 2022 to ensure the plan is effective as of 2022.
Many commenters supported providing incentives for states and utilities to deploy CO
The CEIP is designed to incentivize investment in certain RE and demand-side EE projects that commence construction in the case of RE, or commence operation in the case of EE, following the submission of a final state plan to the EPA, or after September 6, 2018, for states that choose not to submit a final state plan by that date, and that generate MWh (RE) or reduce end-use energy demand (EE) during 2020 and/or 2021. State participation in the program is optional; the EPA is establishing this program as an additional flexibility to facilitate achievement of the CO
Under the CEIP, a state may set aside allowances from the CO
The EPA has determined that the size of this 300 million short ton CO
For a state to be eligible for a matching award of allowances or ERCs from the EPA, it must demonstrate that it will award allowances or ERCs only to eligible projects. These are projects that:
• Are located in or benefit a state that has submitted a final state plan that includes requirements establishing its participation in the CEIP;
• Are implemented following the submission of a final state plan to the EPA, or after September 6, 2018, for a state that chooses not to submit a complete state plan by that date;
• For RE: Generate metered MWh from any type of wind or solar resources;
• For EE: Result in quantified and verified electricity savings (MWh) through demand-side EE implemented in low-income communities; and
• Generate or save MWh in 2020 and/or 2021.
The following provisions outline how a state may award early action ERCs or allowances to eligible projects, and how the EPA will provide matching ERCs or allowances to states.
• For RE projects that generate metered MWh from any type of wind or solar resources: For every two MWh generated, the project will receive one early action ERC (or the equivalent number of allowances) from the state, and the EPA will provide one matching ERC (or the equivalent number of allowances) to the state to award to the project.
• For EE projects implemented in low-income communities: For every two MWh in end-use demand savings achieved, the project will receive two early action ERCs (or the equivalent number of allowances) from the state, and the EPA will provide two matching ERCs (or the equivalent number of allowances) to the state to award to the project.
Early action allowances or ERCs awarded by the state, and matching allowances or ERCs awarded by the EPA pursuant to the CEIP, may be used for compliance by an affected EGU with its emission standards and are fully transferrable prior to such use.
The EPA discusses the CEIP in the proposed federal plan rule, and will address design and implementation details of the CEIP, including the appropriate factor for determining equivalence between allowances and MWh and the definition of a low-income community for project eligibility purposes, in a subsequent action. Before doing so, the EPA will engage states and stakeholders to gather additional information concerning implementation topics, and to solicit information about the concerns, interests and priorities of states, stakeholders and the public.
In order for a state that chooses to participate in the CEIP to be eligible for a future award of allowances or ERCs from the EPA, a state must include in its initial submittal a non-binding statement of intent to participate in the program. In the case of a state submitting a final plan by September 6, 2016, the state plan would either include requirements establishing the necessary infrastructure to implement such a program and authorizing its affected EGUs to use early action allowances or ERCs as appropriate, or would include a non-binding statement of intent as part of its supporting documentation and revise its plan to include those requirements at a later date.
Following approval of a final state plan that includes requirements for implementing the CEIP, the agency will create an account of matching allowances or ERCs for the state that reflects the pro rata share—based on the amount of the reductions from 2012 levels the affected EGUs in the state are required to achieve relative to those in the other participating states—of the 300 million short ton CO
Any matching allowances or ERCs that remain undistributed after September 6, 2018,
For purposes of establishing a state plan program eligible for an award of matching allowances or ERCs from the EPA, such a program must include a mechanism for awarding early action emission allowances or ERCs for eligible actions that reduce or avoid CO
The EPA is providing the CEIP as an option for states implementing plans—and is including a similar program for the federal plan proposal being issued concurrently—for several reasons. Chief among them is that offered by commenters to the effect that the overall cost of achievement of the emission performance rates or state goals could be reduced by an approach that granted some form of beneficial recognition to emissions reduction investments that both occur and yield reductions prior to the first date on which the program of the interim plan performance period. Other commenters pointed out that to the extent that states and utilities would benefit from the availability of low-cost RE and other zero-emitting generation options during the interim and final plan performance periods, the EPA should include in the final emission guidelines provisions that accelerate deployment of RE resources, since in so doing the final emission guidelines would speed achievement of expected reductions in the cost of those technologies commensurate with their accelerated deployment. In addition, the incentives and market signal generated by the CEIP can help sustain the momentum toward greater RE investment in the period between now and 2022 so as to offset any dampening effects that might be created by setting the start date 2 years later than at proposal.
The specific criteria the EPA is establishing for eligible RE projects reflect a variety of considerations. First, the EPA seeks to preserve the incentive for project developers to execute on planned investments in all types of solar and wind technologies. Commenters raised concerns that the fast pace of reductions underlying the emission targets in the proposed rule could potentially shift investment from RE to natural gas, thus dampening the incentive to develop wind and solar projects, in particular. Second, the EPA, consistent with the CAA's design that incentivizes technology and accelerates the decline in the costs of technology, seeks to drive the widespread development and deployment of wind and solar, as these broad categories of renewable technology are essential to longer term climate strategies. Finally, in contrast to other CO
The specific criterion the EPA is establishing for eligible EE projects—namely that these projects be implemented in low-income communities—is also consistent with the technology-forcing and development design of CAA section 111. The EPA believes it is appropriate to offer an additional incentive to remove current barriers to implementing demand-side EE programs in low-income communities. While the EPA acknowledges that a number of states have demand-side EE programs focused on these communities,
More broadly, the CEIP responds to the urgency of meeting the challenge of climate change in two key ways. First, of course, it fosters reductions before 2022. Second, in targeting investments in wind, solar and low-income EE, it focuses on the kinds of measures and technologies that are the essential foundation of longer-term climate strategies, strategies that inevitably depend on the further development and widespread deployment of highly adaptable zero-emitting technologies.
We are not requiring that projects demonstrate to states that they are “additional” or surplus relative to a business-as-usual or state goal-related baseline in order to be eligible. At the same time, we believe that including an incentive to develop projects that benefit low-income communities will increase the likelihood of investments being made that would not have been made otherwise.
In order to be awarded matching ERCs or allowances by the EPA for projects that meet the eligibility criteria, a final state plan must have requirements establishing the appropriate infrastructure to issue early action ERCs or allowances to eligible project providers by 2020. The state must require that the state or its agent will, in accordance with state plan requirements approved as meeting the ERC issuance and EM&V requirements included in section VIII.K: (1) Evaluate project proposals from eligible RE and demand-side EE project providers, including the EM&V plans that must accompany such proposals; (2) evaluate monitoring and verification reports submitted by eligible providers following project implementation, which contain the quantified and verified MWh of RE generation or energy savings achieved
The CEIP will provide a number of benefits. First, the program will provide incentives designed to reduce energy bills early in the implementation of the guidelines through earlier and broader application of energy saving technologies, and help ensure that these benefits are fully shared by low-income communities. Second, the EPA believes that stimulating or supporting early investment in RE generation technologies could accelerate the rate at which the costs of these technologies fall over the course of the interim performance period. Third, the CEIP will provide affected EGUs and states with additional emission reduction resources to help them achieve their state plan obligations. Finally, the program will improve the liquidity, in the early years of the program, of the ERC and allowance markets we expect to emerge for compliance with the requirements of these guidelines.
The EPA is establishing this program as an option for states that wish to drive investments in RE and low-income EE that will result in actual, early reductions in CO
Under the final emission guidelines, states may adopt and submit either of two different types of state plans. The first would apply all requirements for meeting the emission guidelines to affected EGUs in the form of federally enforceable emission standards.
These two types of state plans and their respective approaches, either of which could be implemented on a single-state or multi-state basis, allow states to meet the statutory requirements of CAA section 111(d) while accommodating the wide range of regulatory requirements and other programs that states have deployed or will deploy in the electricity sector that reduce CO
Under these two basic plan types, the final emission guidelines provide states with a number of potential plan pathways for meeting the emission guidelines. A plan pathway represents a specific plan design approach used to meet the emission guidelines. These plan pathways are discussed in section VIII.C.2 through C.5 below, and further elaborated in sections VIII.J (for mass-based emission standards) and VIII.K (for rate-based emission standards).
The final emission guidelines provide four streamlined plan pathways. These streamlined plan pathways represent straightforward plan approaches for meeting the emission guidelines, and avoid the need to meet additional plan requirements and include additional elements in a plan submittal. The streamlined plan pathways include the following:
• Establishing federally enforceable, mass-based CO
• Establishing federally enforceable, mass-based CO
• Establishing federally enforceable, subcategory-specific rate-based CO
• Establishing federally enforceable rate-based CO
The final emission guidelines also provide for a range of additional custom plan approaches that a state may pursue, if it chooses, to address specific circumstances or policy objectives in a state. The custom plan pathways, while viable options for meeting the emission guidelines, come with additional plan requirements and plan submittal elements. These additional plan requirements and plan submittal elements are necessary to ensure that the emission guidelines are met and that the necessary level of CO
Based on this overall approach, the final emission guidelines provide for a range of state options—both easily implementable approaches that can be used to meet the emission guidelines, and more customizable approaches that can be used, if a state chooses, to address special circumstances or state policy objectives.
The emission standards type of state plan imposes requirements solely on affected EGUs in the form of federally enforceable emission standards. This type of state plan, as described below, may consist of rate-based emission standards for affected EGUs or mass-based emission standards for affected EGUs.
The state plan submittal for an emission standards type plan must demonstrate that these federally enforceable emission standards for affected EGUs will achieve the CO
Both rate-based and mass-based emission standards included in a state plan must be quantifiable, verifiable, enforceable, non-duplicative and permanent. These requirements are described in more detail at section VIII.D.2.
Rate-based and mass-based emission standards may incorporate the use of emission trading, as described below. The EPA anticipates the use of emission trading in state plans, given the advantages of this approach and comments suggesting a high degree of interest on the part of states, utilities, and independent power producers in the inclusion of emission trading in state plans.
The EPA notes it is proposing model rules for both mass-based and rate-based emission trading programs. States could adopt and submit the finalized model rules for either emission trading program to meet the requirements of CAA section 111(d) and these emission guidelines. The EPA will evaluate the approvability of such submission, as with any state plan submission, through independent notice-and-comment rulemaking. The EPA notes that state plan submittals that adopt the finalized model rule may be administratively and technically more straightforward for the EPA in evaluating approvability, as the EPA will have determined that the model rule meets the applicable requirements of the emission guidelines through the process of finalization of such rule.
a.
A rate-based “emission standards” plan may be designed to either meet the CO
Under these two approaches, compliance by affected EGUs with the rate-based emission standards in a plan would ensure that affected EGUs meet the CO
Alternatively, if a state chooses, it could apply rate-based emission standards to individual affected EGUs, or to categories of affected EGUs, at a lb CO
Under this type of approach, therefore, the state would be required to include a demonstration,
Under a rate-based approach, a state may include in its plan a number of provisions to facilitate affected EGU compliance with the emission standards. First, a state may encourage (or require) EGUs to undertake actions to reduce CO
ERCs would be issued by the administering state regulatory body. The state may issue ERCs to affected EGUs that emit below a specified CO
Eligible measures that may generate ERCs, as well as the accounting method for adjusting a CO
(1)
As discussed in further detail in section VIII.D.2.d.3, regarding the legal considerations and statutory language of CAA section 111(h), the EPA is finalizing that design, equipment, work practice, and operational standards cannot be considered to be “standards of performance” for this final rule. However, a state may elect to use emission standards for affected EGUs that result in a reduced CO
An approvable plan could apply such emission standards to a subset of affected EGUs or all affected EGUs. As with any rate-based plan, the state would need to demonstrate that the plan would achieve the required level of emission performance for affected EGUs, in CO
As with all emission standards, emission standards based on design, equipment, work practice, and operational standards must be quantifiable, verifiable, enforceable, non-duplicative and permanent. These requirements are described in more detail at section VIII.D.2.
(2)
Additional considerations and requirements for rate-based emission standards state plans are addressed in section VIII.K. This includes the basic accounting method for adjusting the reported CO
b.
The second “emission standards” approach a state may elect to use is mass-based emission standards applied to affected EGUs. Under this approach, the plan would include federally enforceable emission standards for mass CO
Under a mass-based approach, a state could require that individual affected EGUs meet a specified mass emission standard. Alternatively, a state could choose to implement a market-based emission budget trading program. The EPA envisions that the latter option is most likely to be exercised by states seeking to implement a mass-based emission standard approach, as it would maximize compliance flexibility for affected EGUs and enable the state to meet its mass goal in the most economically efficient manner possible.
(1)
One pathway a state could take to achieve its mass-based CO
(2)
A second pathway a state could take to achieve its mass-based CO
An emission budget trading program establishes a combined emission standard for a group of emission sources in the form of an emission budget. Emission allowances are issued in an amount up to the established emission budget.
The EPA views an emission budget trading program as a highly efficient, market-based approach for reducing CO
Additional considerations and requirements for mass-based emission standards state plans are addressed in section VIII.J. This includes use of emission budget trading programs in a state plan, including provisions required for such programs (section VIII.J.2.a) and the design of such programs in the context of a state plan. Section VIII.J addresses program design approaches that ensure achievement of a state mass-based CO
(3)
As discussed in section VIII.C.2.a.(1) above, a state may elect to use mass-based emission standards for affected EGUs that result in a reduced total tonnage of CO
An approvable plan could apply such emission standards to a subset of affected EGUs or all affected EGUs. As with any mass-based plan, the state would need to demonstrate that the plan would achieve the required level of emission performance for affected EGUs, in total tons of CO
The second type of state plan is what we refer to as a “state measures” plan. As previously discussed, the EPA believes states will be able to submit state plans under the emission standards plan type, and its respective approaches, and achieve the CO
Measures implemented under the state measures plan type could include RE and demand-side EE requirements and deployment programs. This type of plan could align with existing state resource planning in the electricity sector, including RE and demand-side EE investments by state-regulated electric utilities. The state measures plan type also can accommodate emission budget trading programs that address a broader set of emission sources than just affected EGUs subject to CAA section 111(d), such as the programs currently implemented by California and the RGGI participating states. The EPA also notes that the state measures plan type could accommodate imposition by a state of a fee for CO
This plan type would allow the state to implement a suite of state measures that are adopted, implemented, and enforceable only under state law, and rely upon such measures in achieving the required level of CO
For a state measures plan to be approvable, it must include a demonstration of how the measures, whether state measures alone or state measures in conjunction with any federally enforceable emission standards for affected EGUs, will achieve the state mass-based CO
a.
Under the state measures plan type, state measures must be satisfactorily described in the supporting material for a state plan submittal. The supporting material would need to demonstrate that the state measures meet the same integrity elements that would apply to federally enforceable emission standards. Specifically, the state plan submittal must demonstrate that the state measures are quantifiable, verifiable, enforceable, non-duplicative and permanent. These requirements are described in more detail at section VIII.D.2. Under the state measures plan, if a state chooses to impose emission standards on affected EGUs, such emission standards must be included in the federally enforceable plan as they would be under an emission standards plan.
The EPA would assess the overall approvability of a state measures plan based, in part, on the state's satisfactory demonstration that the state measures, in conjunction with any federally enforceable emission standards on the affected EGUs that might be included in the plan, would result in the state plan's achievement of the mass-based CO
The EPA's evaluation of the approvability of a state measures plan would also include an assessment of whether the backstop consisting of federally enforceable emission standards for the state's affected EGUs would ensure that the required emission performance level is fully achieved by affected EGUs, in the case that the state measures fail to achieve the state mass-based CO
b.
As further discussed in section VIII.C.6.c, the EPA believes a backstop, composed of federally enforceable emission standards for the affected EGUs that are sufficient to achieve the state CO
These federally enforceable emission standards must be designed such that compliance by affected EGUs with the emission standards would achieve the CO
The state measures plan must specify the trigger and conditions under which the backstop federally enforceable emission standards would apply that is consistent with the requirements in the emission guidelines. The trigger and attendant conditions for deployment of the backstop would address the CAA section 111(d) requirement that states submit a program that provides for the implementation of standards of performance. The state measures plan must specify the level of emission performance that will be achieved by affected EGUs as a result of implementation of the state measures plan during the interim and final plan performance periods. This includes the level of emission performance during the interim plan periods 2022-2024, 2025-2027 and 2028-2029, as well as the performance level that would be achieved during every subsequent 2-year final plan performance period (2030-2031, and subsequent 2-year periods). If actual CO
The backstop emission standards must make up for the shortfall in CO
For example, assume a state measures plan identified a mass-based CO
The EPA received a wide range of comments on the basic plan approaches in the proposal. Numerous commenters supported providing states with the option of implementing a rate-based or mass-based approach. Some commenters expressed concern that a rate-based approach would not reduce overall emissions, and could actually lead to increased emissions. The EPA does not agree with this latter comment, because both approaches would result in adequate and appropriate constraints on CO
Numerous commenters supported allowing states to implement a rate-based emission standard approach applied to affected EGUs. There was also broad support in comments for allowing states to pursue a mass-based approach in the form of mass emission standards on affected EGUs. The EPA is finalizing both of these approaches.
The EPA received a mix of comments for and against the proposed portfolio approach, in which state requirements and other measures that apply to non-EGU entities would be part of a state's federally enforceable state plan. Multiple commenters supported the portfolio approach because it would align with existing state and utility planning processes in the electric power sector, and would maximize state discretion and flexibility in developing plans. Commenters mentioned the range of state requirements and utility programs overseen by states that could be used under a portfolio approach and result in achieving the CO
By contrast, multiple commenters opposed the portfolio approach. Some commenters questioned how a portfolio approach would work, and whether the EPA had provided sufficient detail explaining how such a plan approach could be implemented by a state. In particular, multiple commenters questioned how different state programs, such as utility-administered EE programs, could be made federally enforceable in practice under CAA section 111(d).
After considering these comments, the EPA is not finalizing the portfolio approach or the state commitment variant. However, the EPA is finalizing the state measures plan type, as described above, which would accommodate state choices and allow states to rely upon a variety of measures, as was envisioned under the portfolio approach, in a way that meets the statutory requirements of CAA section 111(d).
The EPA views the ability of a state to implement an individual plan or a multi-state plan as a significant flexibility that allows a state to tailor implementation of its plan to state policy objectives and circumstances. The EPA sees particular value in multi-state plans and multi-state coordination, which allow states to implement a plan in a coordinated fashion with other states. Such approaches can lead to more efficient implementation, lower compliance costs for affected EGUs and lower impacts on electricity ratepayers. Coordinated approaches also will help states identify and address any potential electric reliability impacts when developing plans.
The EPA received broad support in comments for allowing states to implement multi-state plan approaches, and has made multiple changes in the final rule to address many suggestions outlining different approaches states may want to take. These changes are intended to provide streamlined approaches for multi-state coordination while maintaining transparency and assuring that the CO
The EPA is finalizing two approaches that allow states to coordinate implementation in order to meet the emission guidelines.
First, states may meet the requirements of the emission guidelines and CAA section 111(d) by submitting multi-state plans that address the affected EGUs in a group of states. The EPA is finalizing the proposed approach by which multiple states aggregate their rate or mass CO
Second, the EPA is also finalizing another approach, in response to comments received on the proposed rule. This approach enables states to retain their individual state goals for affected EGUs and submit individual plans, but to coordinate plan implementation with other states through the interstate transfer of ERCs or emission allowances.
States have the option to implement this second approach in different ways, as discussed in section VIII.C.5.c. These different implementation options allow states to tailor their implementation of linked emission trading programs, based on state policy preferences, as well as economic and other considerations. These different options provide varying levels of state control over emission trading system partners and require varying levels of coordination in the course of state plan development.
In response to comments, the EPA is also further clarifying how multi-state plans with a joint goal for affected EGUs may be implemented. The EPA is clarifying that states may participate in more than one multi-state plan, if necessary, for example, to address affected EGUs in states that are served by more than one ISO or RTO. The EPA is further clarifying that a subset of affected EGUs in a state may participate in a multi-state plan. These clarifications are discussed in section VIII.C.5.d.
a.
Multiple commenters supported the EPA's proposed approach that would allow states to implement a multi-state plan to meet a joint CO
The EPA notes that there are multiple incentives for states to collaborate by implementing a multi-state plan to meet an aggregated joint goal, regardless of the specific level of their individual goals, because states share grid regions and impacts from plan implementation will be regional in nature. Further, multiple analyses, including those by ISOs and RTOs, indicate that regional approaches could achieve state goals at lesser cost than individual state plan approaches. However, the EPA also recognizes the value in allowing for collaboration where states retain individual goals. These approaches could provide some of the benefits of a joint goal while reducing the negotiations among states necessary to develop a multi-state plan with a joint goal. As a result, the EPA has finalized the additional approaches described in section VIII.C.5 to provide for coordination while maintaining individual goals. These approaches would allow for interstate transfer of ERCs or emission allowances while retaining individual state goals.
Many commenters suggested that states should be encouraged to join or form regional market-based programs. Many commenters touted the economic efficiency benefits of such approaches, and noted that such programs have features that support electric reliability.
The EPA agrees with these comments, and notes that it encouraged such approaches in the proposal. While the EPA is not requiring states to join and/or form regional market-based programs, we note that such programs can be helpful for many reasons, including features that support reliability. Market-based programs allow greater flexibility for affected EGUs both in the short-term and long-term. Under a market-based program, affected EGUs have the ability to obtain sufficient allowances or credits to cover their emissions in order to comply with their emission standards. Additionally, we continue to encourage states to cooperate regionally. Regional cooperation in planning and reliability assessments is an important tool to meeting system needs in the most cost-effective, efficient, and reliable way.
b.
Multiple states may submit a multi-state plan that achieves an aggregated joint CO
Under this approach, a rate-based multi-state plan would include a weighted average rate-based emission goal, derived by calculating a weighted average CO
Such plans could include emission standards in the form of a multi-state rate-based or mass-based emission trading program.
c.
States that do not wish to pursue a joint CO
Under this approach, a state plan could indicate that ERCs or CO
The EPA would assess the approvability of each state's plan individually—the use of ERCs or emission allowances issued in another state would not impact the approvability of the components of the individual state plan.
Coordinated state plan implementation among states that retain individual state mass-based CO
d.
The EPA is clarifying in the final emission guidelines that a state may participate in more than one multi-state plan. Under this approach, the state would identify in its submittal the subset of affected EGUs in the state that are subject to the multi-state plan or plans. This could involve a subset of affected EGUs that are subject to a multi-state plan, with the remainder of affected EGUs subject to a state's individual plan. Alternatively, different affected EGUs in a state may be subject to different multi-state plans. In all cases, the state would need to identify in each specific plan which affected EGUs are subject to such plan, with each affected EGU subject to only one multi-state plan or subject only to the state's individual plan (if relevant).
These scenarios may occur where a state chooses to cover affected EGUs in different ISOs or RTOs in different multi-state plans. This will provide states with flexibility to participate in multi-state plans that address the affected EGUs in a respective grid region, in the case where state borders cross grid regions.
These scenarios may also occur where a state is served by multiple vertically integrated electric utilities with service territories that cross state lines. This will provide states with flexibility to participate in multi-state plans that address the affected EGUs owned and operated by a utility with a multi-state service territory.
a.
The emission standards approach is consistent with the requirements of CAA section 111(d). If a state simply adopts the CO
We note that the standard the statute provides for the EPA's review of a state plan is whether it is “satisfactory.” We interpret a “satisfactory” plan as one that meets all applicable requirements of the CAA, including applicable requirements of these guidelines. Some commenters suggested that “satisfactory” should be taken to mean something less (such as mostly or substantially meeting requirements) but the structure of 111(d) shows otherwise. When a state plan is unsatisfactory, section 111(d)(2) gives the EPA the “same” authority to promulgate a federal plan as the EPA has under section 110(c). Under section 110(c), the EPA has authority to promulgate a federal implementation plan if a SIP does not comply with all CAA requirements (see sections 110(k)(3) and 110(l)).
For example, if an emission standards type plan includes an emission standard that is unenforceable due to defective rule language, then the plan is not satisfactory because it does not comply with the guideline requirement that emission standards must be enforceable. On the other hand, if a state plan complies with all applicable requirements of the CAA (including these guidelines), then the EPA must approve it as satisfactory. This is true even if the emission standards in the state plan are more stringent than the minimum requirements of these guidelines, or the state plan achieves more emission reductions than required by these guidelines. This follows from section 116 of the CAA as interpreted by the U.S. Supreme Court in
b.
There are three legal considerations with respect to emissions trading in state plans. First, we explain how the definition of “standard of performance” in section 111(a)(1) allows section 111(d) plans to include standards of performance that authorize emissions trading. Second, we explain how the EPA interprets the phrase “provides for implementation and enforcement of [the] standards of performance” in the context of a rate-based ERC trading program. Third, we give a similar explanation of the EPA's interpretation of the same phrase in the context of a mass-based allowance trading program.
(1). In the proposal, the EPA proposed that CAA section 111(d) plans may include standards of performance that authorize emissions averaging and trading. 79 FR 34830, 34927/1 (June 18, 2014). We are finalizing that states may include the use of emission trading in approvable state plans.
For purposes of this legal discussion, in the case of an emission limitation expressed as an emission rate, trading takes the form of buying or selling ERCs that an affected EGU may generate if its actual emission rate is lower than its allowed emission rate or that an eligible resource may generate. In the case of an emission limitation expressed as a mass-based limit, trading takes the form of buying or selling allowances.
As quoted in full above, the definition of “standard of performance” under CAA section 111(a)(1) is a “standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which . . . the Administrator determines has been adequately demonstrated.”
Both an emission rate that may be met through tradable ERCs, and a mass limit requirement that emissions not exceed the number of tradable allowances surrendered by an affected source, qualify as a “standard for emissions.” The term “standard” is not defined, but its everyday meaning is a rule or
Treating a tradable emission rate or mass limit requirement as a “standard of performance” is consistent with past EPA practice. In the Clean Air Mercury Rule, promulgated in 2005, the EPA established tradable mass limits as the emission guidelines for certain air pollutants from fossil fuel-fired EGUs, and explained that a tradable mass limit qualifies as a “standard for emissions.”
It should be noted that CAA section 302(l) includes another definition of “standard of performance,” which is “a requirement of continuous emission reduction, including any requirement relating to the operation or maintenance of a source to assure continuous emission reduction.” As described above, section 111(d) contains its own, more specific definition of “standard of performance,” which a tradable emission rate or mass limit satisfies. Whether or not section 302(l) applies in light of section 111(d)'s more specific definition, a tradable emission rate or mass limit also meets section 302(l)'s requirements. A tradable emission rate applies continuously in that the source is under a continuous obligation to meet its emission rate, and that is so regardless of the averaging time,
(2). In our final rule, we are prescribing certain specific requirements for trading systems for ERCs in a rate-based approach. These specific requirements are in addition to the generic requirements for any state plan (see section VIII.D.2.d below for the legal basis for the generic components for state plans) and are intended to ensure the integrity of the ERC trading system. The integrity of the trading system is key to ensuring that a state plan provides for implementation and enforcement of the standards of performance, as required by section 111(d)(1)(B). Requirements relating to ERCs in a rate-based trading system, and allowances in a mass-based system, must also be submitted as federally enforceable components of the state plan, as such requirements provide for the implementation and enforcement of a tradable emission rate or mass limit for an affected EGU.
However, as described in section VIII.C.6.d, the EPA has legal concerns regarding whether federally enforceable requirements under a CAA section 111(d) state plan can be imposed on entities other than affected EGUs. It is important to note that the use of ERCs and inclusion of state plan requirements regarding a rate-based trading system, and the use of allowances and inclusion of state plan requirements regarding a mass-based trading system, does not run afoul of these legal concerns, as neither the requirements of section 111(d) nor of the federally enforceable state plan in either case extend to non-EGU generators or third-party verifiers of such compliance units.
(3). In our final rule, we are prescribing certain specific requirements for trading systems for allowances in a mass-based approach. These specific requirements are in addition to the generic requirements for any state plan (see section VIII.D.2.d below for the legal basis for the generic requirements for state plans) and are intended to ensure the integrity of the allowance trading system. The integrity of the trading system is key to ensuring that a state plan provides for implementation and enforcement of the standards of performance.
c.
The EPA believes the state measures plan type is consistent with CAA section 111(d). Section 111(d)(1) requires a state to submit a plan that “(A) establishes standards of performance for any existing source for [certain] air pollutant[s] . . . and (B) provides for the implementation and enforcement of such standards of performance.” Section 111(d)(2)(A) indicates that the EPA must approve the state plan if it is “satisfactory.”
For states that choose to adopt and submit a state measures plan, such state must submit a state plan that includes standards of performance for CO
Additionally, under the state measures plan type, if a state chooses to impose emission standards for the affected EGUs in conjunction with state measures that apply to other entities for any period prior to the triggering of the backstop, this final rule requires such emission standards to be submitted as federally enforceable measures included in the state plan. The EPA believes this is appropriate to help ensure the performance of a state measures plan will meet the requirements of this final rule. Section 111(d) clearly authorizes states to impose, and the EPA to approve, federally enforceable emission standards for affected EGUs. Though federally enforceable emission standards for affected EGUs in a state
Section 111(d)(1)(B) also requires a state to submit a program that provides for the implementation and enforcement of the applicable standards of performance. Under the state measures approach, this requirement regarding implementation is satisfied in part by the submission of an approvable trigger mechanism for the backstop and appropriate monitoring, reporting and recordkeeping requirements. The trigger mechanism provides for the “implementation” of the backstop,
Additionally, by requiring states that choose to impose emission standards on affected EGUs under the state measures approach to submit such emission standards for inclusion in the federally enforceable plan, this requirement further provides for implementation and enforcement as required by the statute. Regulating the affected EGUs through federally enforceable emission standards themselves in conjunction with any state measures the state chooses to rely upon further assures the likelihood of the affected EGUs achieving the state goals as required under this rule and section 111(d).
The state measures plan is a variation of the proposed portfolio approach in that both plan types allow the state to rely upon measures that impose requirements on sources other than affected EGUs in meeting the requisite state CO
The state measures plan type the EPA is finalizing is also a logical outgrowth of the comments received on the proposed portfolio approach. As further explained below, legal questions remain as to whether state plans under section 111(d) can include federally enforceable measures that impose requirements on sources other than affected EGUs. However, a number of commenters and stakeholders expressed robust support for the ability to rely on measures and programs that do not impose requirements on affected EGUs themselves through plan types such as the proposed portfolio and state commitment approaches. The EPA is reasonably interpreting 111(d) as authorizing the state measures plan type, and believes this plan type is also responsive to, and accommodating of, states and stakeholders who have expressed the importance of being able to rely upon various measures that have the effect of reducing CO
The EPA additionally notes that the state measures plan type is not precluded by the recent Ninth Circuit Court of Appeals' decision in
There are a number of reasons why this decision does not preclude the state measures plan type. The Ninth Circuit's textual analysis does not apply here, as the language of section 110(a)(2)(A) does not control for 111(d) state plans. Section 111(d)(1) requires state plans to “establish standards of performance” and to “provide for implementation and enforcement” of the standards of performance, but, unlike section 110(a)(2)(A), section 111(d) does not specifically say that every emission reduction measure must be “included” in the state plan and be made federally enforceable. Even if section 111(d) did impose such requirements, the state measures approach satisfies them because the trigger is included in the plan as a federally enforceable implementation measure, and the backstop included in the plan also contains standards of performance that reflect the BSER and are federally enforceable once they are triggered.
The Ninth Circuit's structural analysis also does not apply. The availability of the trigger and backstop gives the EPA
d.
The EPA is not finalizing the portfolio approach that was included in the proposed rulemaking, 79 FR 34830, 34902 (June 18, 2014). In the proposal, the EPA noted that the portfolio approach raised legal questions. 79 FR 34830, 34902-03. A number of commenters stated that the portfolio approach is unlawful because it exceeds the limitations that section 111(d)(1) places on state plans. Upon further review, we agree with these comments.
Section 111(d)(1) provides that state plans shall “establish[] “standards of performance for any existing source” and “provide[] for the implementation and enforcement of . . . standards of performance” under CAA section 111(d)(1). Although in the proposal we identified possible interpretations of section 111(d)(1) that could justify the proposed portfolio approach, after reviewing the comments, we are not adopting those interpretations. Because section 111(d)(1) specifically requires state plans to include only (A) standards for emissions imposed on affected sources and (B) measures that implement and enforce such standards,
We note that section 111(d) limits on federal enforceability of requirements against non-affected sources do not imply that the BSER cannot be based on actions by non-affected sources. As discussed in section V, the BSER may be based on the ability of owners/operators of affected sources to engage in commercial relationships with a wide range of other entities, from the vendors, installers, and operators of air pollution control equipment to, in this rulemaking, owners/operators of RE.
The EPA notes it is also not finalizing the proposed state commitment approach or state crediting approach. The EPA believes the finalized state measures plan type provides states with the same flexibilities as would have been allowed under these two proposed approaches, and does so in a way that is legally supportable by the CAA. Therefore, the EPA does not believe it necessary to finalize the state commitment approach or state crediting approach.
e.
While nothing in section 111(d)(1) explicitly authorizes either states to adopt and submit multi-state plans, or the EPA to approve them as satisfactory, nothing in section 111(d)(1) explicitly prohibits it, either. In addition, nothing in section 111(d)(2)(A)'s standard of “satisfactory” prohibits the EPA from considering multi-state plans as satisfactory. There is thus a gap that the EPA may reasonably fill.
In light of the purpose of these emission guidelines, to reduce emissions of a pollutant that globally mixes in the stratosphere, and the mechanisms to reduce those emissions, which may have beneficial effects across state lines, it is reasonable to allow for multi-state plans. Thus, our gap-filling interpretation of section 111(d) in this context is reasonable.
In the “Criteria for Approving State Plans” section of the preamble to the June 2014 proposal (section VIII.C), the EPA proposed the following as necessary components of an approvable state plan:
1. The plan must contain enforceable measures that reduce EGU CO
2. The projected CO
3. The EGU CO
4. The plan must include a process for state reporting of plan implementation, CO
After reviewing the comments we received concerning the approvability criteria, the EPA has decided against maintaining the four proposed approvability criteria separately from the list of components required for an approvable plan, which may be confusing and potentially redundant. The EPA has determined that a satisfactory state plan that meets the required plan components discussed below will inevitably meet the proposed approvability criteria. The EPA, therefore, has incorporated the proposed approvability criteria into the section titled “Components of a state plan submittal” (section VIII.D.2 below). There is no functional change in the approvability criteria or the components of a state plan addressed in the proposal; they are simply combined and this change does not have a substantive effect on state plan development or approval.
Under the proposed “Enforceable Measures” criterion (section VIII.C.1 of the proposal preamble), the EPA specifically requested comment on the appropriateness of applying existing EPA guidance on enforceability to state plans under CAA section 111(d), considering the types of entities that might be included in a state plan.
The EPA also requested comment on whether the agency should provide guidance on enforceability considerations related to requirements in a state plan for entities other than affected EGUs, and if so, what types of entities. Comments received strongly suggested that the EPA provide guidance on enforceability considerations for non-EGU affected entities, particularly for RE and EE. Comments also requested additional guidance specific to this rulemaking, including examples of enforceable measures for specific activities, such as
These enforcement considerations arose primarily under the proposed portfolio approach for state plans, which would have allowed state plans to include federally enforceable measures that apply to entities that are not affected EGUs. In this action, the EPA is finalizing the state measures approach instead of the portfolio approach, under which a state can rely upon measures that are not federally enforceable as long as the plan also includes a backstop of federally enforceable emission standards that apply to affected EGUs. As explained in depth in section VIII.C, if the state is adopting the state measures approach, the state plan submittal will need to specify, in the supporting materials, the state-enforceable measures that the state is relying upon, in conjunction with any federally enforceable emission standards for affected EGUs, to meet the emission guidelines. As part of the state measures approach, the EPA is finalizing a requirement for a federally enforceable backstop, which requires the affected EGUs to meet emission standards that fully achieve the CO
Commenters also requested that the EPA allow states to rely on provisions with flexible compliance mechanisms in state plans and clarify how to address flexible compliance mechanisms when demonstrating achievement of a state CO
In this action, the EPA is finalizing that a state plan submittal must include the components described below. As a result of constructive comments received from many commenters and additional considerations, the EPA is finalizing state plan components that are responsive to that input and are appropriate for the types of state plans allowed in the final emission guidelines. A state plan submittal must also be consistent with additional specific requirements elsewhere in this final rule and with the EPA implementing regulations at 40 CFR 60.23-60.29, except as otherwise specified by this final rule. These requirements apply to both individual state plan submittals and multi-state plan submittals. When a state plan submittal is approved by the EPA, the EPA will codify the approved CAA section 111(d) state plan in 40 CFR part 62. Section VIII.D.3 discusses the components of a state plan submittal that would be codified as the state CAA section 111(d) plan when the state plan submittal is approved by the EPA.
The EPA is finalizing that states can choose to meet the emission guidelines through one of two types of state plans: an emission standards plan type or a state measures plan type. A state pursuing the emission standards plan type may opt to submit a plan that meets the CO
The rest of this section covers components that are required for all types of plans, as well as components specific to each specific type of plans. Section VIII.D.2.a addresses the components required for all plan submittals. Section VIII.D.2.b addresses the additional components required for submittals under the emission standards plan type. Section VIII.D.2.c addresses additional components required for submittals under the state measures plan type.
a.
The EPA is finalizing requirements that a final plan submittal must contain the following components, in addition to those in either section VIII.D.2.b (for the emission standards plan type) or VIII.D.2.c (for the state measures plan type) of this section.
(1)
The description of the plan type must indicate whether the state will meet the emission guidelines on an individual state basis or jointly through a multi-state plan, and whether the state is adopting an emission standards plan type or a state measures plan type. For multi-state plans this component must identify all participating states and geographic boundaries applicable to each component in the plan submittal. If a state intends to implement its individual plan in coordination with other states by allowing for the interstate transfer of ERCs or emission allowances, such links must also be identified.
(2)
The state plan submittal must list the individual affected EGUs that meet the applicability criteria of 40 CFR 60.5845 and provide an inventory of CO
(3)
A state plan submittal must demonstrate that the federally
The type of demonstration of CO
(a)
• State plan establishes separate rate-based CO
• State plan establishes a single rate-based CO
• State plan establishes mass-based CO
• State plan establishes mass-based CO
All other state plan designs must include a projection of CO
For example, if a state chooses to apply rate-based CO
(b)
(c)
The CO
• Geographic representation, which must be appropriate for capturing impacts and/or changes in the electric system
• Time period of analysis, which must extend through 2031
• Electricity demand forecast (MWh load and MW peak demand) at the state and regional level. If the demand forecast is not from NERC, an ISO or RTO, EIA, or other publicly available source, then the projection must include justification and documentation of underlying assumptions that inform the development of the demand forecast, such as annual economic and demand growth rate, population growth rate.
• Planning reserve margins
• Planned new electric generating capacity
• Analytic treatment of the potential for building unplanned new electric generating capacity
• Wholesale electricity prices
• Fuel prices, when applicable;
• Fuel carbon content
• Unit-level fixed operations and maintenance costs, when applicable;
• Unit-level variable operations and maintenance costs, when applicable;
• Unit-level capacity
• Unit-level heat rate
• If applicable, EGU-specific actions in the state plan designed to meet the required CO
• If applicable, state-enforceable measures, with electricity savings and renewable electricity generation (MWhs) expected for individual and collective measures, as applicable. Quantification of MWhs expected from EE and RE measures will involve assumptions that states must document, as described in the Incorporating RE and Demand-side EE Impacts into State Plan Demonstrations TSD.
• Annual electricity generation (MWh) by fuel type and CO
• ERC or emission allowance prices, when applicable
The state must also provide a clear demonstration that the state measures and/or federally enforceable emission standards informing the projected achievement of the emission performance requirements will be permanent and remain in place.
The EPA encourages participation in regional modeling efforts which are designed to allow sharing of data and help promote consistent approaches across state boundaries. A state that submits a single-state plan must consider interstate transfer of electricity across state boundaries, taking into account other states' plan types reflecting the best available information at the time of the CO
(d)
The projection will involve an analysis of the change in generation of affected EGUs given the compliance costs and incentives under the application of different emission rate standards across affected EGUs in a state. It must accurately represent the emission standards in the plan, including the use of market-based aspects of the emission standards (if applicable), such as use of ERCs or emission allowances as compliance instruments.
In addition to the elements described in the previous section (c), the projection under this plan design must include:
• The assignment of federally enforceable emission standards for each affected EGUs;
• A projection showing how generation is expected to shift between affected EGUs and across affected EGUs and non-affected EGUs over time;
• Underlying assumptions regarding the availability and anticipated use of the MWh of electricity generation or electricity savings from eligible measures that can be issued ERCs;
• The specific calculation (or assumption) of how eligible MWh of electricity generation or savings that can be issued ERCs are being used in the projection to adjust the reported CO
• ERC prices, if applicable;
• If a state plan provides for the ability of RE resources located in states with mass-based plans to be issued ERCs for use in adjusting the reported CO
• Any other applicable assumptions used in the projection.
(e)
A state must demonstrate that its state-enforceable measures, along with any federally enforceable CO
• The assignment of federally enforceable emission standards for each affected EGUs, if applicable; and
• the individual state measures, including their projected impacts over time.
Because different types of state measures could have varying degrees of impact on reducing or avoiding CO
(4)
The state plan submittal must specify how each emission standard is quantifiable and verifiable by describing the CO
In the June 2014 proposal, the EPA proposed that states must include in their state plans a record retention requirement for affected EGUs to maintain records for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report or record. Commenters requested clarification of the record retention requirements for states as compared to for affected EGUs and also requested that the EPA clarify onsite versus offsite record maintenance requirements for affected EGUs. The EPA is finalizing that states must include in their plans a record retention requirement for affected EGUs of not less than 5 years following the date of each compliance period, compliance true-up period, occurrence, measurement, maintenance, corrective action, report, or record, whichever is latest. Affected EGUs must maintain each record onsite for at least 2 years after the date of the occurrence of each record and may maintain records offsite and electronically for the remaining years. Each record must be in a form suitable and readily available for expeditious review. The EPA finds that these final recordkeeping requirements are appropriate and consistent with the requirements for other CAA section 111(d) emission guidelines.
(5)
A state plan submittal must contain the process, content and schedule for state reporting to the EPA on plan implementation and progress toward meeting the CO
The EPA requested comments on whether full reports containing all of the report elements should only be required every 2 years and on the appropriate frequency of reporting of the different proposed elements, considering both the goals of minimizing unnecessary burdens on states and ensuring program transparency and effectiveness. Commenters recognized that different reporting frequencies may be appropriate for different types of state plans. The EPA agrees with the commenters and is finalizing state reporting requirements based on the type of plan the state chooses to adopt and implement. These state reporting requirements and reporting periods are discussed in section VIII.D.2.b (for emission standards plan types) and VIII.D.2.c (for state measures plan types). The EPA finalizes that each state report is due to the EPA no later than the July 1 following the end of each reporting period. The EPA recognizes the multiple comments received recommending extending the state report due date from July 1 to a later date or to allow the states the flexibility to propose an alternative report submittal date. The EPA is not pursuing these recommendations due to the implications of the state reports' due date and the trigger and schedule for implementation of corrective measures (for the emission standards approach) or the backstop federally enforceable emission standards (for the state measures approach). The EPA believes the July 1 deadline for states to submit reports to the EPA on plan implementation is feasible given that the information required to be included in the reports will be available per the reporting requirements for affected EGUs in state plans.
In addition to the state reporting requirements discussed in section VIII.D.2.b (for emission standards approach) and VIII.D.2.c (for state measures approach) and as discussed below, states must include in the supporting material of a final state plan submittal a timeline with all the programmatic plan milestone steps the state will take between the time of the final state plan submittal and 2022 to ensure the plan is effective as of 2022. The EPA is also finalizing a requirement that states must submit a report to the EPA in 2021 that demonstrates that the state has met the programmatic plan milestone steps that the state indicated it would take from the submittal of the final plan through the end of 2020, and that the state is on track to implement the approved state plan as of January 1, 2022. A final state plan submission must include a requirement for the state to submit this report to the EPA no later than July 1, 2021. This report will help the EPA further assist and facilitate plan implementation with states as part of an ongoing joint effort to ensure the necessary reductions are achieved.
The EPA is finalizing the requirement that submissions related to this program be submitted electronically. Specifically, this includes negative declarations, state plan submittals (including any supporting materials that are part of a state plan submittal), any plan revisions, and all reports required by the state plan. The EPA is developing an electronic system to support this requirement that can be accessed at the EPA's Central Data Exchange (CDX) (
In the June 2014 proposal, the EPA proposed that states must keep records, for a minimum of 20 years, of all plan components, plan requirements, plan supporting documentation and status of meeting the plan requirements, including records of all data submitted by each affected EGU used to determine compliance with its emission standards. The EPA received multiple comments recommending that the EPA reduce recordkeeping requirements due to the burden in expenditure of resources and manpower to maintain records for at least 20 years. Commenters recommended that recordkeeping requirements be reduced to 5 years consistent with emission guidelines for other existing sources.
After considering the comments received, this final rule requires that a state must keep records of all plan components, plan requirements, supporting documentation, and the status of meeting the plan requirements defined in the plan for the interim plan period from 2022-2029 (including interim steps 1, 2 and 3). After 2029, states must keep records of all information relied upon in support of any continued demonstration that the final CO
(6)
A robust and meaningful public participation process during state plan development is critical. For the final plan submittal, states must meaningfully engage with members of the public, including vulnerable communities, during the plan development process. This section describes how the EPA will evaluate a state plan for compliance with the minimum required elements for public participation provided in the existing implementing regulations as well as recommendations for other steps the state can take to assure robust and inclusive public participation.
The existing implementing regulations regarding public participation requirements are in 40 CFR 60.23(c)-(f). Per the implementing regulations, states must conduct a public hearing on a final state plan before such plan is adopted and submitted. State plan development can be enhanced by tapping the expertise and program experience of several state government agencies. The EPA encourages states to include utility regulators (
As previously discussed in this rule, recent studies also find that certain communities, including low-income communities and some communities of color (more specifically, populations defined jointly by ethnic/racial characteristics and geographic location) are disproportionately affected by certain climate change related impacts.
In addition, certain communities whose economies are significantly dependent on coal, or whose economies may be affected by ongoing changes in the utility power and related sectors, may be particularly concerned about the final rule. The EPA encourages states to make an effort to provide background information about their proposed initial submittal and final state plans to these communities in advance of their public hearing. In particular, the EPA encourages states to engage with workers and their representatives in the utility and related sectors, including the EE sector.
The EPA notes that meaningful public involvement goes beyond the holding of a public hearing. The EPA envisions meaningful engagement to include outreach to vulnerable communities, sharing information and soliciting input on state plan development and on any accompanying assessments, such as those described in section IX. The agency uses the terms “vulnerable” and “overburdened” in referring to low-income communities, communities of color, and indigenous populations that are most affected by, and least resilient to, the impacts of climate change, and are central to our community and environmental justice considerations. In section VIII.E, the EPA provides states with examples of resources on how they can engage with vulnerable communities in a meaningful way. With respect specifically to ensuring meaningful community involvement in their public hearing(s), however, the EPA recommends that states have both a Web site and toll-free number that all stakeholders, including overburdened communities, labor unions, and others can access to get more information regarding the upcoming hearing(s) and to get their questions related to upcoming hearings answered. Furthermore, the EPA recommends that states work with their local government partners to help them in reaching out to all stakeholders, including vulnerable communities, about the upcoming public hearing(s).
(7)
The state plan submittal must provide supporting material and technical documentation related to applicable components of the plan submittal.
(a)
In its submittal, a state must adequately demonstrate that it has the legal authority (regulations/legislation) and funding to implement and enforce each component of the state plan submittal, including federally enforceable emission standards for affected EGUs and state measures. A state can make such a demonstration by providing supporting material related to the state's legal authority used to implement and enforce each component of the plan, such as copies of statutes, regulations, PUC orders, and any other applicable legal instruments. For states participating in a multi-state plan, the submittal(s) must also include as supporting documentation each state's necessary legal authority to implement the portion of the plan that applies within the particular state, such as copies of state regulations and statutes, including a showing that the states have
(b)
As applicable, the state submittal must include materials necessary to support the EPA's evaluation of the submittal including analytical materials used in the calculation of interim goal steps (if applicable), analytical materials used in the multi-state goal calculation (if multi-state plan), analytical materials used in projecting CO
(c)
As part of the state plan supporting documentation, the state must include in its submittal a timeline with all the programmatic plan milestone steps the state will take between the time of the state plan submittal and 2022 to ensure the plan is effective as of January 1, 2022. The programmatic plan milestones and timeline should be appropriate to the overall state plan approach included in the state plan submittal.
(d)
As discussed in more detail in section VIII.G.2, each state must demonstrate as part of its state plan submission that it has considered reliability issues while developing its plan.
b.
(1)
The state plan submittal must indicate whether the plan is designed to meet the CO
Each state plan submittal must identify the emission performance rates or rate-based or mass-based CO
The EPA has finalized an interim performance rates or state goal for the interim period of 2022-2029 and a final performance rates or state goal to be met by 2030. For the interim period, the EPA has also finalized three interim step performance rates or state goals: interim step 1 performance rates or state goal for 2022-2024, interim step 2 performance rates or state goal for 2025-2027 and interim step 3 performance rates or state goal for 2028-2029.
For states participating in a multi-state plan with a joint goal (for interim and final periods), the individual state goals in the emission guidelines would be replaced with an equivalent multi-state goal for each period (interim and final). For a rate-based multi-state plan this would be a weighted average rate-based emission goal, derived by the participating states, by calculating a weighted average CO
(2)
The state plan submittal for an emission standards plan type must include federally enforceable emission standards that apply to affected EGUs. The emission standards must meet the requirement of component (3) of this section, “Demonstrations that each emission standard is quantifiable, non-duplicative, permanent, verifiable, and enforceable.” The plan must identify the affected EGUs to which these standards apply. The compliance periods for each emission standard for affected EGUs, on a calendar year basis, must be as follows for the interim period: January 1, 2022-December 31, 2024; January 1, 2025-December 31, 2027; and January 1, 2028-December 31, 2029. Starting on January 1, 2030, the compliance period for each emission standard is every 2 calendar years. States can choose to set shorter compliance periods for the emission standards than the compliance periods the EPA is finalizing in this rulemaking, but cannot set longer periods. As discussed in more detail in section VIII.F, the EPA recognizes that the compliance periods provided for in this rulemaking are longer than those historically and typically specified in CAA rulemakings. The EPA determined that the longer compliance periods provided for in this rulemaking are acceptable in the context of this specific rulemaking because of the unique characteristics of this rulemaking, including that CO
For state plans in which affected EGUs may rely upon the use of ERCs for meeting a rate-based federally enforceable emission standard, the state plan must include requirements addressing the issuance, tracking and use for compliance of ERCs consistent with the requirements in the emission guidelines. These requirements are discussed in sections VIII.K.1-2. The state plan must also demonstrate that the appropriate ERC tracking infrastructure that meets the
For state plans using a mass-based emission trading program approach, the state plan must include implementation requirements that specify the emission budget and related compliance requirements and mechanisms. These requirements must include: CO
(3)
The plan submittal must demonstrate that each emission standard is quantifiable, non-duplicative, permanent, verifiable and enforceable with respect to an affected EGU, as outlined below.
An emission standard is quantifiable if it can be reliably measured, using technically sound methods, in a manner that can be replicated.
An emission standard is non-duplicative with respect to an affected EGU if it is not already incorporated in another state plan, except in instances where incorporated as part of a multi-state plan. An example of a duplicative emission standard would occur, for example, where a quantified and verified MWh from a wind turbine could be applied in more than one state's CAA section 111(d) plan to adjust the reported CO
An emission standard is permanent if the emission standard must be met for each applicable compliance period.
An emission standard is verifiable if adequate monitoring, recordkeeping and reporting requirements are in place to enable the state and the Administrator to independently evaluate, measure, and verify compliance with it.
An emission standard is enforceable if: (1) It represents a technically accurate limitation or requirement and the time period for the limitation or requirement is specified; (2) compliance requirements are clearly defined; (3) the entities responsible for compliance and liable for violations can be identified; and (4) each compliance activity or measure is enforceable as a practical matter in accordance with EPA guidance on practical enforceability,
In developing its CAA section 111(d) plan, to ensure that the plan submittal is enforceable and in conformance with the CAA, a state should follow the EPA's prior guidance on enforceability.
In the proposed regulatory text describing the enforcing measures that states must include in state plans, the EPA inadvertently excluded a required demonstration that states and other third parties can enforce against affected EGUs for violations of an emission standard included in a state plan via civil action pursuant to CAA section 304. Commenters noted the EPA's intent to require this demonstration based on statements in both the proposal preamble text and “State Plan Considerations” TSD
(4)
After consideration of the comments received regarding state reporting
The state must include in each report to the EPA the status of implementation of emission standards for affected EGUs under the state plan, including current aggregate and individual CO
As discussed in more detail in section VIII.F, the state must include an interim performance check in the report submitted after each of the first two interim step periods. The interim performance check will compare the CO
For state plans that use the emission standards approach and are subject to the corrective measures provisions in the emission guidelines, if actual CO
c.
The EPA is finalizing requirements that a final plan submittal using the state measures approach must contain the following components, in addition to the components discussed in section VIII.D.2.a. We note again that states choosing the state measures plan type must use a mass-based state goal for the state measures and any emission standards on the affected EGUs prior to the triggering of the backstop.
(1)
The state plan submittal must identify the mass-based CO
For each state, the EPA has finalized an interim goal for the interim period of 2022-2029 and a final goal to be met by 2030. For the interim period, the EPA has also finalized three interim step goals: Interim step 1 goal for 2022-2024, interim step 2 goal for 2025-2027 and interim step 3 goal for 2028-2029.
For states participating in a multi-state plan with a joint goal (for interim and final periods), the individual state goals in the emission guidelines would be replaced with an equivalent multi-state goal for each period (interim and final). The joint goal would be a sum of the individual mass-based goals of the participating states, in tons of CO
(2)
If applicable, the state plan submittal must include any federally enforceable CO
(3)
A state measures plan must include a backstop of federally enforceable emission standards for affected EGUs that fully achieve the interim and final CO
(4)
A state adopting a state measures plan type must provide as a part of the supporting documentation of its plan submittal, a description of all the state enforceable measures the state will rely upon to achieve the requisite state mass-based goal, the applicable state laws or regulations related to such measures, and identification of parties or entities implementing or complying with such state measures. The state must also include in its supporting documentation the schedule and milestones for the implementation of the state measures, showing that the measures are expected to achieve the mass-based CO
(5)
After consideration of the comments received regarding state reporting requirements, the EPA is requiring in this final rule for states using the state measures approach that an annual state report is due to the EPA no later than July 1 following the end of each calendar year during the interim period. This annual state report must include the status of implementation of federally enforceable emission standards (if applicable) and state measures, and must include a report of the periodic programmatic state measures milestones to show progress in program implementation. The programmatic state measures milestones with specific dates for achievement should be appropriate to the state measures described in the supporting documentation of the state plan submittal. The EPA believes that annual state reporting is appropriate for state measures approach due to the flexibility inherent to the approach described in section VIII.C.3 including the potential use by the state of a wider variety of state measures, responsible parties, etc. This reporting frequency will also increase the degree of certainty on plan performance for states pursuing the state measures approach.
As discussed in section VIII.F, for states using the state measures approach, the EPA is finalizing that at the end of the first two interim step periods, the state must also include in their annual report to the EPA the corresponding emission performance checks. The interim performance checks will compare the CO
Beginning with the final period, the state must submit biennial reports no later than July 1 after the end of each reporting period that includes an actual performance check to demonstrate that the state continues to meet the final state CO
If, at the time of the state report to the EPA, the state has not met the programmatic state measures milestones for the reporting period, or the performance check shows that the actual CO
(6)
(a)
A state using the state measures approach, in support of its plan, must also include in the supporting documentation of the state plan submittal the state measures that are not federally enforceable emission standards, and describe how each state measure is quantifiable, non-duplicative, permanent, verifiable, and enforceable with respect to an affected entity.
A state measure is quantifiable if it can be reliably measured, using technically sound methods, in a manner that can be replicated.
A state measure is non-duplicative with respect to an affected entity if it is not already incorporated as a state measure or an emission standard in another state plan or state plan supporting material, except in instances where incorporated in another state as part of a multi-state plan. This does not mean that measures in a state measure cannot also be used for other purposes. For example actions taken pursuant to CAA section 111(d) requirements can satisfy other CAA program requirements (
A state measure is permanent if the state measure must be met for each applicable compliance period.
A state measure is verifiable if adequate monitoring, recordkeeping and reporting requirements are in place to enable the state to independently evaluate, measure and verify compliance with it.
A state measure is enforceable
The EPA will disapprove a state plan if the documentation is not sufficient for the EPA to be able to determine whether the state measures are expected to yield CO
d.
(1)
Under section 111(d), state plans must “provide for the implementation and enforcement of [the] standards of performance.” Similar language occurs elsewhere in the CAA. First, for SIPs, section 110(a)(1) requires SIPs to “provide for implementation, maintenance, and enforcement” of the NAAQS. However, section 110(a)(2), unlike 111(d), details a number of specific requirements for SIPs that, in part, speak exactly to how a SIP should “provide for implementation, maintenance, and enforcement” of the NAAQS. We note that section 111(d) provides explicitly only that the “procedures,” and not the substantive requirements, for section 111(d) state plans should be “similar” to those in section 110, and thus a substantive requirement in section 110(a)(2) is not an independent source of authority for the EPA to require the same for section 111(d) plans. However, when there is a gap for the EPA to fill in interpreting how a section 111(d) plan should “provide for implementation and enforcement of [the] standards of performance,” and Congress explicitly addressed a similar gap in section 110, then it may be reasonable for the EPA to fill the gap in section 111(d) using an analogous mechanism to that in section 110(a)(2), to the extent that the section 110(a)(2) requirement makes sense and is reasonable in the context of section 111(d). On the other hand, that Congress did not explicitly provide such details as are found in section 110(a)(2) indicates that Congress intended to give the EPA considerable leeway in interpreting the ambiguous phrase “provides for implementation and enforcement of [the] standards of performance.”
For example, section 110(a)(2)(E)(i) explicitly requires states to provide necessary assurances that they have adequate personnel, funding and authority to carry out the SIP. Section 111(d), on the other hand, does not explicitly contain this requirement. Thus, there is a gap to fill with respect to this issue when the EPA interprets section 111(d)'s requirement that plans “provide for implementation and enforcement” of the standards of performance, and it is reasonable for the EPA to fill the gap by requiring adequate funding and authority, both because adequate funding and authority are fundamental prerequisites to adequate implementation and enforcement of any program, and because Congress has explicitly recognized this fundamental nature in the section 110 context.
We note two other places where the CAA requires a state program to satisfy similar language regarding implementation and enforcement. First, section 112(l)(1) allows states to adopt and submit a program for “implementation and enforcement” of section 112 standards. Section 112(l)(5) further provides that the program must (among other things) have adequate authority to enforce against sources, and adequate authority and resources to implement the program. Second, section 111(c) provides that, if a state develops and submits “adequate procedures” for “implementing and enforcing” section 111(b) standards of performance for new sources in that state, the Administrator shall delegate to the state the Administrator's authority to “implement and enforce” those standards. The EPA has interpreted these ambiguous provisions in the EPA's “Good Practices Manual for Delegation of NSPS and NESHAPS” and recommended (in the context of guidance) that state programs have a number of components, such as source monitoring, recordkeeping, and reporting, in order to adequately implement and enforce section 111(b) or 112 standards. This again indicates it is reasonable for the EPA to fill a gap in section 111(d)'s language and similarly require source monitoring, recordkeeping, and reporting, as these are fundamental to implementing and enforcing standards of performance that achieve the state performance rates or goals.
Some commenters argued that states have primary authority over the content of state plans and that the EPA lacks authority to disapprove a state plan as unsatisfactory simply because it lacks one or more of these components. We disagree. The EPA has the authority to interpret the statutory language of section 111(d) and to make rules that effectuate that interpretation. With respect to the components of an approvable plan, we are interpreting the statutory phrase “provide for implementation and enforcement” and making rules that set out the minimum elements that are necessary for a state plan to be “satisfactory” in meeting this statutory requirement. This does not in any way intrude on the state's ability to decide what mix of measures should be used to achieve the necessary emission reductions. Nor does it intrude in any way on the state's ability to decide how to satisfy a component. For example, for legal authority, we are not dictating which state agencies or officials must specifically have the necessary legal authority; that is entirely up to the state so long as the fundamental requirement to have adequate legal authority to implement and enforce the plan is met.
In addition, the EPA has already determined in the 1975 implementing regulations that certain components, such as monitoring, recordkeeping, and reporting, are necessary for implementation and enforcement of section 111(d) standards of performance. 40 FR 53340, 53348/1 (Nov. 17, 1975). Thus, EPA's position here is hardly novel. The EPA notes in discussing the implementing regulations, nothing in this final rule reopens provisions or issues that were previously decided in the original promulgation of the regulations unless otherwise explicitly reopened for this rule.
(2)
In the proposed rulemaking, the EPA proposed the interpretation that if an existing source is subject to a section 111(d) state plan, and then undertakes a modification or reconstruction, the source remains subject to the state plan, while also becoming subject to the modification or reconstruction
(3)
In the proposal, the EPA asked for comment on three approaches to inclusion of design, equipment, work practice and operational standards in section 111(d) plans. 79 FR 34830, 34926/3 (June 18, 2014). Under the first approach, states would be precluded from including these standards in section 111(d) plans unless the design, equipment, work practice or operational standard could be understood as a “standard of performance” or could be understood to “provide for implementation and enforcement” of standards of performance. We also asked, for the first approach, whether it was even possible, given the statutory language of 111(h), to consider a design, equipment, work practice or operational standard as a “standard of performance.” Under the second approach, states could include design, equipment, work practice or operational standards in the event that it could be shown a “standard of performance” was not feasible, as set out in section 111(h). Under the third approach, a state could include design, equipment, work practice and operational standards in a 111(d) plan without any constraints. We also asked whether, if there was legal uncertainty as to the status of these standards, the EPA should authorize states to include them in their 111(d) plans with the understanding that if the EPA's authorization were invalidated by a court, states would have to revise their plans accordingly.
The EPA is finalizing the first approach. Specifically, a state's standards of performance (in other words, either the federally enforceable backstop under the state measures approach or the emission standards under the emission standards approach) cannot consist of (in whole or part) design, equipment, work practice or operational standards. A state may include such standards in a 111(d) plan in order to implement the standards of performance. For example, a state taking a mass-based approach may include in its 111(d) plan a limit on hours of operation on a particular affected EGU, but that operational standard itself cannot substitute for a mass-based emission standard on the affected EGU.
This follows from the statute. First, section 111(h)(1) authorizes the Administrator, when it is not feasible for certain reasons (specified in 111(h)(2)) to prescribe or enforce a standard of performance, to instead promulgate a design, equipment, work practice or operational standard. If a standard of performance could include design, equipment, work practice or operational standards, such authority would be unnecessary. Second, 111(h)(5) states that design, equipment, work practice or operational standards “described in” 111(h) shall be treated as standards of performance for the purposes of the CAA. This creates a strong inference that standards of performance otherwise should not include design, equipment, work practice, or operational standards. Finally, the general definition of “standard of performance” in section 302(l) is similar to the definition of “emission limitation” (or “emission standard”) in section 302(k), with the exception that the definition of “emission limitation” explicitly includes design, equipment, work practice and operational standards, but the definition of “standard of performance” omits them. Thus, as with our discussion of the term “standard of performance” above in VIII.C.6.b, even if the general definition of “standard of performance” in 302(l) applies to 111(d), the omission of design, equipment, work practice, and operational standards in 302(l) confirms our interpretation that they cannot be a 111 “standard of performance” (except under the limited circumstances in 111(h)). We conclude that it is reasonable, and perhaps compelled, to interpret the term “standards of performance” in 111(d) to not include design, equipment, work practice and operational standards.
However, section 111(d) requires plans to “provide for implementation and enforcement of [the] standards of performance.” This language does not explicitly prohibit a plan from including design, equipment, work practice and operational standards, and allows for them to be included so long as they are understood to provide for implementation of the standards of performance. If they are included, the 111(d) plan must still be “satisfactory” in other respects, in particular in establishing standards of performance that are not in whole or in part design, equipment, work practice, and operational standards.
(4)
As previously discussed, section 111(d)(1) requires the EPA to promulgate procedures “similar” to those in section 110 under which states adopt and submit 111(d) plans. Section 110(a)(1) requires states to adopt and submit implementation plans “after reasonable notice and public hearings.” The implementing regulations under 40 CFR 60.27 reflect similar public participation requirements with respect to section 111(d) state plans. The EPA is sensitive to the legal importance of adequate public participation in the state plan process, including public participation by affected communities. As previously discussed in this rule, recent studies also find that certain communities, including low-income communities and some communities of color, are disproportionately affected by certain climate change-related impacts. Because certain communities have a potential likelihood to be impacted by state plans for this rule, the EPA believes that the existing public participation requirements under 40 CFR 60.23 are effectuated for the purposes of this final rule by states engaging in meaningful, active ways with such communities. By requiring states to demonstrate how they have meaningfully engaged with vulnerable communities potentially impacted by state plans as part of the state plan development process, states meeting this requirement will satisfy the applicable statutory and regulatory requirements regarding public participation.
In this action the EPA finalizes that, to be fully approved, a state plan submittal must meet the criteria and include the required components described above. The EPA will propose and take final action on each state plan submittal in the
In this action the EPA is finalizing that state plan submittals are due on September 6, 2016, with the option of an extension to submit final state plans by September 6, 2018, which is 3 years after finalization of this rule. The compelling nature of the climate change challenge, and the need to begin promptly what will be a lengthy effort to implement the requirements of these guidelines, warrant this schedule. The EPA also believes, for reasons further described in the next section, why this schedule is achievable for states to submit final plans. We discuss the timing of state plans in more detail in this section below.
Discussed in the following sections are state plan submittal and timing, required components for initial submittals and the 2017 update, multi-state plan submissions, process for EPA review of state plans, failure to submit a plan, state plan modifications (including modifications to interim and final CO
The implementing regulations (40 CFR 60.23) require that state plans be submitted to the EPA within 9 months of promulgation of the emission guidelines, unless the EPA specifies otherwise.
In the proposal, EPA proposed a 13 month final state plan submittal deadline, with a 1 year possible extension for states submitting individual state plans and a 2 year possible extension for states submitting multi-state plans as part of a multi-state region. The EPA received substantive comment on the achievability of these proposed deadlines for state plan submittals. Multiple commenters expressed concern that due to timing of legislative cycles (some of which are every 2 years), regulatory processes, and other necessary tasks, states would find it extremely difficult to submit plans in 1 or 2 years, whether or not they were planning to submit as part of a multi-state region. The EPA agrees based on this input that a schedule shorter than 3 years will be challenging for many—though not all—states. In light of the comments received and in order to provide maximum flexibility to states while still taking timely action to reduce CO
The EPA highlights that one purpose of the initial submittal is to encourage and potentially facilitate states to do necessary planning and engagement with stakeholders so states are able to submit an approvable final state plan by the extended deadline of September 6, 2018. Some states have well-developed existing programs and the attendant legal authority underpinning such programs to more easily meet the September 6, 2016 deadline by submitting a final plan which largely contains or relies upon such existing programs.
Additionally, some states may not submit a state plan as required by the final emission guidelines and section 111(d) of the CAA. For states that do not submit a state plan, the CAA gives the EPA express authority to implement a federal plan for sources in that state upon determination by the EPA that a state has failed to submit a state plan by the required date. For states that do not intend to submit a state plan to meet the obligations of this final rule, by promulgating a federal plan for affected EGUs in states that do not submit a plan by September 6, 2016, such affected EGUs would have a maximum of an
If no affected EGU is located within a state, the state must submit a letter to the EPA certifying that no such facilities exist by September 6, 2016.
In the case of a tribe that has one or more affected EGUs located in its area of Indian country, if the tribe either does not submit a CAA section 111(d) plan or does not receive EPA approval of a submitted plan, the EPA has the responsibility to establish a CAA section 111(d) plan for that area if it determines that such a plan is necessary or appropriate to protect air quality.
The EPA notes that the current implementing regulations at 40 CFR part 60 do not specify who has the authority to make a formal submission of the state plan to the EPA for review. In order to clarify who on behalf of a state is authorized to submit an initial submittal, 2017 update, final state plan (or negative declaration, if applicable), and any revisions to an approved plan, the EPA has included a requirement in this final rule mirroring that of the requirement in 40 CFR part 51 App. V.2.1.(a) with respect to SIPs that identifies the Governor of a state as the authorized official for submitting the state plan to the EPA. If the Governor wishes to designate another responsible official the authority to submit a state plan, the EPA must be notified via letter from the Governor prior to the 2016 deadline for plan submittal so that they have the ability to submit the initial submittal or final plan in the State Plan Electronic Collection System (SPeCS). If the Governor has previously delegated authority to make CAA submittals on the Governor's behalf, a state may submit documentation of the delegation in lieu of a letter from the Governor. The letter or documentation must identify the designee to whom authority is being designated and must include the name and contact information for the designee and also identify the state plan preparers who will need access to SPeCS discussed in section VIII.E.8. A state may also submit the names of the state plan preparers via a separate letter prior to the designation letter from the Governor in order to expedite the state plan administrative process. Required contact information for the designee and preparers includes the person's title, organization and email address. The EPA recommends this information be submitted early in the state planning process to allow sufficient time for completion of SPeCS registration so that those authorized to use the system are provided access.
As noted, states may request a 2-year extension to submit a final plan through making an initial submittal by September 6, 2016. For the extension to be granted, the EPA is finalizing that the initial submittal must address three required components sufficiently to demonstrate that a state is able to undertake steps and processes necessary to timely submit a final plan by the extended date of September 6, 2018:
• An identification of final plan approach or approaches under consideration, including a description of progress made to date.
• An appropriate explanation for why the state requires additional time to submit a final plan by September 6, 2018.
• Demonstration or description of opportunity for public comment on the initial submittal and meaningful engagement with stakeholders,
During the public comment period, multiple commenters stated that the proposed timeframe for states to submit an initial submittal was not achievable, citing, among other things, the number of decisions needed to be made by a state or states, and that the EPA needed to clarify the requirements for an initial submittal. Multiple commenters also expressed concern that the requirements for an initial submittal required final decisions to be made by states, and that the initial submittal deadline was not enough time for states to make these decisions.
It is important to note that the EPA is not requiring the adoption of any enforceable measures or final decisions in order for the state to address any of the initial submittal components by September 6, 2016. The EPA believes the absence of requiring enforceable measures to be included with the initial submittal greatly supports the ability of states intending to develop a final state plan to submit an initial submittal by September 6, 2016. States are required to submit enforceable measures supported by technically complex documentation, such as modeling, and adopted through state public participation and regulatory or legislative processes as part of SIPs under other parts of the CAA within timeframes comparable to the time the EPA is providing for initial submittals.
In order to further address the commenters' concerns regarding possible ambiguity of the requirements for an initial submittal so that an extension is granted, the EPA is providing clarity regarding the required components for an initial submittal. Regarding the component that states address an appropriate explanation for an extension, the EPA proposed that appropriate explanations for seeking an extension beyond 2016 for submitting a final plan include: A state's required schedule for legislative approval and administrative rulemaking, the need for multi-state coordination in the development of an individual state plan, or the process and coordination necessary to develop a multi-state plan. In this final rule, the EPA is finalizing these as appropriate explanations for seeking an extension beyond 2016, but makes clear—as explained further below—that other appropriate explanations will be acceptable as well. It is important to note that the initial submittal does not require legislation
In order to additionally clarify the required components of the initial submittal, the following are types of explanations of information states may provide as part of the initial submittal to sufficiently address each of the three required components for getting an extension:
• Details on whether a state is considering a single or multi-state plan, a plan that meets the CO
• A description of how the state intends to address development of the required components of the final state plan, including describing what actions have already been taken, what steps remain, and the schedule for completing those steps.
• A commitment to maintain any existing measures the state intends to rely upon for its final plan in order to achieve the necessary reductions once the performance period begins.
• Describing public participation opportunities such as stakeholder and community meetings, or public hearings, throughout the 3 year plan development process. This could also include leverage of public participation approaches that states already use to identify and engage potentially affected communities.
The EPA emphasizes the required initial submittal components are intended to provide a reasonable pathway for states to demonstrate whether they will be able to submit an approvable plan by the extended date of September 6, 2018. The EPA also anticipates that through the requirement to address these components, the initial submittal will also facilitate state planning and stakeholder engagement, particularly as one component requires the public and stakeholders to have an opportunity to comment on the initial submittal. As previously described, these components do not require final decisions to be made by states, and this is further illustrated by the clarifications on how states may meet each of the three required components. Accordingly, the EPA believes none of these components is onerous for states to address in an initial submittal by the September 6, 2016 deadline. To further underscore this point, the EPA is further explaining the clarifying examples listed above of how states may address the three required components, and highlighting the achievability of these examples for states to address through the initial submittal by September 6, 2016.
For identification of the final plan approach or approaches the state is considering, and description of progress made to date, states could identify whether the state is considering the option of the CO
The EPA received substantive comment regarding the potential adverse consequences for states pursuing a multi-state approach and receiving an extension until 2018, where, for various reasons, a state or states then decide(s) to pursue the single state approach. Commenters viewed this as being potentially problematic since, as proposed, a single state could only receive an extension until 2017, and if a multi-state plan effort does not work out the deadline for seeking the extension until 2017 would have passed. The EPA notes finalizing a 2 year extension that is available for any state, whether they are pursuing an individual state plan or a multi-state plan resolves the commenters' concern about conflicting extension deadlines if states involved in a multi-state effort decide not to pursue the multi-state approach. Importantly, such identification in an initial submittal does not obligate the state to then actually adopt that approach in their final plan as the EPA acknowledges that based on state processes and public input through plan development during the extended submission period, a state may end up adopting a state plan approach more suitable to the needs of that state and its affected EGUs than previously identified in the initial submittal.
States can also describe progress made to date by identifying steps already taken to address development of the final state plan, as the EPA recognizes that states in general have already taken a number of steps to prepare for state plan development to meet the obligations of this rule. For example, since proposal, states have: Begun exploring tradeoffs among various state plan approaches such as individual versus multistate coordination, increased utilization of demand-side EE and RE programs, and implementing rate-based versus mass-based programs; increased their understanding of existing state programs and policies that reduce carbon emissions; built relationships and communications between key state institutions such as environmental agencies, PUCs, governors' offices, and energy regulators; hosted public stakeholder meetings to educate and solicit input from the public; and begun discussing state processes for developing potential state plans. States may meet the first required component by describing steps such as these already undertaken.
The EPA underscores that states may easily address the first component of the initial submittal by describing such steps, and also address the second required component by identifying next steps (which may be a natural extension of these already implemented activities), and laying out a schedule for development of a final plan. States that have taken these steps would especially
An initial submittal that contains a commitment to maintain any existing measures the state intends to rely upon for its final plan in order to get the necessary reductions once the performance period begins (
Regarding the required public participation component of the initial submittal, the EPA believes this requirement is both achievable for states to submit an initial submittal by the September 6, 2016 deadline, and provides a benefit in facilitating state plan development so that states are more likely to be able to submit a final plan within 3 years if the extension is granted. The EPA can use a comment opportunity on the initial submittal to advise the state whether aspects of the draft initial submittal and overall plan development are appropriate for purposes of meeting the requirements of the final rule so that the state will be able to procure the extension through an acceptable initial submittal and submit a final plan by the extended deadline. The EPA notes the comment period on the initial submittal is only one opportunity the EPA has to assist a state in the state plan development process. The EPA has historically worked with states throughout the state plan development process to help ensure that the state plan is approvable once submitted to the EPA, and expects this level of engagement with states to continue throughout the plan development process. This requirement will also facilitate early identification of concerns stakeholders and the public may have with aspects of a final plan the state is considering. As states have longtime and extensive experience with responding to public comments in numerous contexts, including in the context of other CAA programs such as section 110 SIP development and in permit issuance under NSR and Title V, the EPA anticipates states will be able to timely address the initial submittal public participation.
As previously discussed, because certain communities have a potential likelihood to be impacted by state plans, the EPA believes that the existing public participation requirements under 40 CFR 60.23 are effectuated for the purposes of this final rule by states engaging in meaningful, active ways with such communities. Therefore, the public participation component of the initial submittal includes meaningful engagement with vulnerable communities, throughout the state plan development process and including through the initial submittal. In order to demonstrate to the EPA that states are actively engaging with communities, states could provide in their initial submittal a summary of steps they have already taken to engage the public and how they intend to continue meaningful engagement, including with vulnerable communities, during the additional time (if an extension is granted) for development of the final plan. In addition to approaches that states already use to identify and engage potentially affected communities, the EPA encourages states to use the proximity analysis conducted for this rulemaking (which is described in section IX.A) as a tool to help them identify overburdened communities that could be potentially impacted by their plans. Other tools, such as EJ screen, can also be helpful. The EPA in its continued outreach with states during the implementation phase will also provide resources to assist them in engaging with communities. The EPA believes that through the provision of these resources states will also more easily be able to address this required component of the initial submittal regarding public engagement, including with vulnerable communities, by September 6, 2016.
In addition to the resources the EPA intends to provide to states, there are existing resources states can take advantage of to address this component as well. On the steps that states could take to engage vulnerable communities in a meaningful way, the Agency recommends that states consult the EPA's May 2015
The EPA recommends that as part of their meaningful engagement with vulnerable communities, states work with communities to ensure that they have a clear understanding of the benefits and any potential adverse impacts that a state plan might have on their overburdened communities and that there is a clear process for states to respond to input from communities.
If a state seeks an extension by submitting an appropriate initial submittal addressing the three required components as described above by September 6, 2016, the EPA will review the submittal. If the state does not submit an initial submittal by September 6, 2016, that contains the three required components, the EPA
For states that request and receive a 2-year extension, the state must submit an update halfway through that extension, by September 6, 2017. In the proposal the EPA included a requirement regarding a 2017 check in. Because the EPA is finalizing that states are able to get a 2-year extension regardless of whether they are submitting an individual or multi state final plan, the EPA believes it appropriate to ensure through the 2017 update that the state is making continuous progress on its initial submittal and that it is on track to meet the final plan submittal deadline of September 6, 2018. The EPA will also be able to use the information provided through the 2017 update to further assist states in plan development.
The final rule requires that states address in the 2017 update the following components:
• A summary of the status with respect to required components of the final plan, including a list of which components are not yet complete.
• A commitment to a plan approach (
• An updated comprehensive roadmap with a schedule and milestones for completing the plan, including progress to date in developing a final plan and steps taken in furtherance of actions needed to finalize a final plan.
In order to assess whether a state is on track to submit a final plan by the 2018 extension deadline, the EPA is requiring that the 2017 update must contain a progress update on components from the initial submittal and a list of which final plan components are still not complete.
The EPA is also requiring that the 2017 update include a commitment to the type of plan approach the state will take in the final plan submittal. During the public comment period, many commenters stated that legislative action would be required to enact this final rule at the state level, and that the proposal did not provide enough time for legislative action or other regulatory actions needed for a state to be granted an extension. In order to respond to these comments, the EPA is clarifying that proposed or passed legislation or regulations are not required in the initial submittal due by September 6, 2016. While a state may indicate consideration of multiple state plan approaches in the initial submittal, the EPA is requiring that the state commit to one approach in the 2017 update. This commitment must include draft or proposed legislation or regulations that must become final at the state level prior to submitting a final plan submittal to the EPA. While commenters expressed concern with not being able to have legislation enacted in time to receive an extension until 2018, the EPA has determined that 2 years is a reasonable timeframe for a state to decide on the type of approach it will take in the final plan submittal and to draft legislation or regulations for this approach in order to timely meet the extended September 6, 2018 deadline.
For states wishing to participate in a multi-state plan, the EPA is finalizing three forms of submittal that states may choose for the submittal of a multi-state plan.
First, the EPA is finalizing its proposed approach where one multi-state plan submittal is made on behalf of all participating states. The joint submittal must be signed by authorized officials for each of the states participating in the multi-state plan and would have the same legal effect as an individual submittal for each participating state. The joint submittal must adequately address plan components that apply jointly for all participating states and for each individual state in the multi-state plan, including necessary state legal authority to implement the plan, such as state regulations and statutes. Because the multi-state plan functions as a single plan, each of the required plan components (
The EPA received comments from states requesting flexibility for multi-state plan submittals. In response to these comments, the EPA is also finalizing two additional options on which it solicited comment. First, states participating in a multi-state plan can provide a single submittal—signed by authorized officials from each participating state—that addresses common plan elements. This option requires individual participating states to provide supplemental individual submittals that provide state-specific elements of the multi-state plan. The common multi-state submittal must address all relevant common plan elements and each individual participating state submittal must address all required plan components (including common plan elements, even if only through cross reference to the common plan submittal). Under this approach, the combined common submittal and each of the individual participating state submittals would constitute the multi-state plan submitted for EPA review. The joint common submittal must be signed by authorized officials for each of the states participating in the multi-state plan and would have the same legal effect as an individual submittal for each participating state.
Second, the EPA is finalizing an approach where all states participating in a multi-state plan separately make individual submittals that address all elements of the multi-state plan. These submittals would need to be materially consistent for all common plan elements that apply to all participating states, and would also address individual state-specific aspects of the multi-state plan. Each individual state plan submittal would need to address all required plan components. The EPA encourages states participating in this type of multi-state plan to use as much common material as possible to ease review of the state plans.
These approaches will provide states with flexibility in addressing contingencies where one or more states submit plan components that are not approvable. In such instances, these options simplify the EPA's approval of remaining common or individual portions of a multi-state plan and help address contingencies during plan development where a state fails to finalize its participation in a multi-state plan, with minimal disruption to the submittals of the remaining participating states. These additional submittal approaches also facilitate multi-state plans where the participating states are coordinating the implementation of their plans but are not taking on a joint multi-state emission goal for affected EGUs. For example, states may seek to engage in a multi-state approach that links rate-based or mass-based emission trading programs through appropriate authorizations (
In order to avoid a multi-state plan becoming unapprovable due to one state submitting an unapprovable portion of a multi-state plan, withdrawing from the multi-state plan, or failing to implement the multi-state plan, states may include express severability clauses if their multi-state plan is able to stand without further revision if one of the situations described above occurs. The severability clause must specify how the remainder of the multi-state plan or individual state plan would continue to function with the withdrawal of a state or states, and may also include pre-specified revisions. The EPA will evaluate the appropriateness of such a clause as part of its review of the multi-state plan submittal.
Our proposal laid out the basic steps for the EPA's review and action on submitted state plans and, at some length, discussed the required components of state plans, as further described in the preceding sections. We received a number of thoughtful and helpful comments on these issues. We are finalizing the basic requirements in this rule and are proposing, in the companion proposed federal plan under section 111(d), some additional procedural elements we believe will be helpful to states, stakeholders and the EPA moving forward.
Following the September 6, 2016 deadline for state plan submittals, the EPA will review plan submittals. For a state that submits an initial submittal by September 6, 2016, and requests an extension of the deadline for the submission of a final state plan submittal, the EPA will determine if the initial submittal meets the minimum requirements for an initial submittal. If the state does not submit an initial submittal by September 6, 2016, that contains the three required components, the EPA will notify the state by letter, within 90 days, that the agency cannot grant the extension request based the state's initial submittal. If the initial submittal meets the minimum requirements specified in the emission guidelines, the state's request for a deadline extension to submit a final plan submittal will be deemed granted, and the final plan submittal must be submitted to the EPA by no later than September 6, 2018.
After receipt of a final plan submittal, the EPA will review the plan submittal and, within 12 months, approve or disapprove the plan through a notice-and-comment rulemaking process publicized in the
In addition, while the proposal and this final rule lay out in considerable detail the required components of a state plan, the EPA believes that it would also be helpful to include in the rule a completeness determination process, similar to that used for SIP submittals under section 110, which will allow the EPA to determine whether a final plan submittal contains the components necessary to enable the EPA to determine through notice and comment rulemaking whether such submittal complies with the requirements of section 111(d). This is a procedural requirement under CAA section 110(k)(1) for SIPs, and the EPA believes this requirement is appropriate to establish under section 111(d)'s direction to the EPA to prescribe through regulations a procedure similar to that provided by section 110. However, because the EPA did not propose such regulations as part of the proposal for this action, the EPA is proposing such regulations as part of the federal plan proposal for section 111(d). The EPA notes that this preamble (in section VIII.D) and final rule lay out required components of state plans and all the requirements for a state plan submittal, and therefore states have the necessary information at this time to develop state plans. The upcoming completeness criteria will not add to or change these required components, but only add a procedural step that allows the EPA to identify whether there are absent or insufficient components in the plan submittal that would render the EPA unable to act on such submittal because it is incomplete. As we further explain in the federal plan proposal, a determination by the EPA that a plan submittal is incomplete has the effect of a state having a still-pending statutory obligation to submit a plan that meets the requirements of section 111(d).
The EPA is planning to propose an amendment to the section 111(d) implementing regulations that will add the partial approval/disapproval and conditional approval mechanisms in section 110(k)(3) and (4) to the procedure for acting on section 111(d) plans. The input the agency received in response to the proposal for these guidelines indicated that the flexibility provided by these mechanisms could be useful getting state plans in place. The EPA agrees, and is proposing to amend the implementing regulations as part of the rulemaking for the federal 111(d) plan. The EPA is not taking final action on these changes in this action.
The later timing for our action on partial approval/disapproval and conditional procedures does not create any issue with finalizing this rule. These procedural adjustments will only come into play after states have submitted their plans and the EPA is required to act on them, and we intend to finalize these procedural changes prior to September 6, 2016, when the first plan submittals would occur. Until then, the EPA believes that every plan is submitted with the intent to be fully approvable and there is no need for states to rely on the possibility of these procedures when developing their plans. Conditional approval and partial approval/disapproval should be used to deal with approvability issues that arise despite the best efforts of states and the EPA to work together to make sure a submittal in the first instance is fully approvable. The EPA plans to finalize any changes in the implementing regulations before the EPA is required to act on state submittals, so that the EPA and states will have appropriate flexibility in the plan approval process.
If a state does not submit a final plan submittal by the applicable deadline, or submits a final plan the EPA determines to be incomplete, the EPA will notify the state by letter of its failure to submit. The EPA will publish a
a.
During the course of implementation of an approved state plan, a state may wish to update or alter one or more of the enforceable measures in the state plan, or replace certain existing enforceable measures with new measures. The EPA received broad support for allowing states to submit modifications to approved state plans, and we agree that this is an important aspect of this program. In this rulemaking, therefore, the EPA is finalizing that a state may revise its state plan, and states in a multi-state plan may revise their joint plan. Consistent with the timing for final plan submittals originally submitted by states, the EPA will act on state plan revisions within 12 months of a complete submittal. The EPA expects that the long plan performance timeframes in this final rule and flexibility provided to states in developing state plans will lessen the need for modifications to approved state plans.
A state may enter or exit a multi-state plan through a plan modification, with certain limitations. Multiple commenters stated that the EPA should clarify the plan modification process in such instances.
Where a state with a single-state approved plan seeks to join a multi-state plan, the state may submit a modification of its plan indicating that it is joining the multi-state plan and including the necessary plan components under the multi-state plan. The current participants of the multi-state plan will also need to submit a plan modification, to acknowledge the new state participant and to recalculate the multi-state rate-based or mass-based CO
The entry or exit of a state to/from a multi-state plan involves the recalculation of the multi-state rate-based or mass-based CO
As a result of these requirements and considerations, the EPA is finalizing certain requirements for multi-state plan modifications. A multi-state plan modification may be submitted to the EPA at any time. However, an approved multi-state plan modification may only take effect at the beginning of a new interim or final plan performance period. These requirements are necessary to ensure that the emission performance rates or state rate-based or mass-based CO
The EPA solicited comment on whether, for new projections of emission performance included in a submitted plan modification, the projection methods, tools, and assumptions used should match those used for the projection in the original demonstration of plan performance, or should be updated to reflect the latest data and assumptions, such as assumptions for current and future economic conditions and technology cost and performance. Comments received on this topic were generally supportive of allowing the use of updated data in state plan modifications, citing that states should have the ability to determine whether the original data and assumptions or updated data and assumptions are appropriate. The EPA is finalizing that new projections of emission performance, the projection methods, tools, and assumptions do not have to match those used for the projection in the original demonstration of plan performance; they can be updated to reflect the latest data and assumptions, such as assumptions for current and future economic conditions and technology cost and performance.
As discussed in more detail in section VIII.G.2, the final rule has several measures to ensure that it does not interfere with the industry's ability to maintain reliability. One such measure is that if a state cannot address a reliability issue in accordance with an approved state plan, the state can submit a request to the EPA to modify the state plan. See section VIII.G.2 for a more detailed discussion of this issue.
The EPA is not finalizing any circumstances under which a state may or may not revise its state plan, with the exception that a state may not revise its state plan in a way that results in the affected EGU or EGUs not meeting the requisite CO
b.
As discussed in section VII, the final rule specifies that the state interim and final CO
The EPA is finalizing the requirement that submissions related to this program
a.
To ensure that the EPA has the ability to identify, evaluate, merge, update and track federally enforceable plan components in a timely and comprehensive manner, the EPA is requiring states to submit an editable copy of the specific plan components in their submittals that are designated as federally enforceable, either effective upon the EPA plan approval or as a state plan backstop measure. The editable version is in addition to the non-editable version. Examples of editable file formats include Microsoft Word, Apple Pages and WordPerfect.
b.
States shall provide the EPA with both a non-editable and editable copy of any submitted revision to existing approved federally enforceable plan components, including state plan backstop measures. The editable copy of any such submitted plan revision must indicate the changes made, if any, to the existing approved federally enforceable plan components, using a mechanism such as redline/strikethrough. This approach to identifying the changes made to the existing federally enforceable plan components is consistent with the criteria for determining the completeness of SIP submissions set forth in Section 2.1(d) of Appendix V to 40 CFR part 51.
c.
It is the EPA's experience that electronic submittal of information has increased the ease and efficiency of data submittal and data accessibility. The EPA is developing the SPeCS, a web accessible electronic system to support this requirement that will be accessed at the EPA's Central Data Exchange (CDX) (
Once in CDX, SPeCS can be selected from the Active Program Service List. The preparer (
The process has been designed to be compliant with the Cross-Media Electronic Reporting Rule (CROMERR), under 40 CFR part 3, which provides the legal framework for electronic reporting under all of the EPA's environmental regulations. The framework includes criteria for assuring that the electronic signature is legally associated with an electronic document for the purpose of expressing the same meaning and intention as would a handwritten signature if affixed to an equivalent paper document. In other words, the electronic signature is as equally enforceable as a paper signature. For more information on CROMERR, see the Web site:
The EPA received a number of comments on the electronic submittal of state plans. Some commenters preferred the option to submit electronically rather than the requirement to do so. In the final rule, for the reasons discussed below, the EPA is requiring electronic submittal of state plans and not allowing alternate options for plan submittal (
Requiring electronic submittal is in keeping with current trends in data availability and will result in less burden on the regulated community. Electronic submittal will facilitate two-way business communication between states and the EPA, will guide states through the submittal process to ensure submission of all required plan components, and will enable states to submit proposed plans to the EPA electronically for early EPA comments. Electronic submittal will also facilitate, expedite and promote national consistency in the EPA's review of state plans and promote transparency by providing stakeholder-specific access to updated information on state plan status and posting of plan requirements for viewing by the public, government regulators and regulated entities. The EPA recently implemented an electronic submittal process for SIPs under CAA section 110 and continues to explore opportunities to increase the ease and efficiency with which states and the regulated community can meet regulatory data submittal requirements. In summary, the EPA believes electronic submittal will be enormously beneficial in terms of improving coordination and cooperation between the EPA and its state partners in developing approvable state plans. We note, however, that there may be some circumstances where having paper copies of the plan is needed to facilitate public engagement, and encourage states to take those considerations into account.
d.
In the proposal, the EPA requested comment on the creation of templates for initial submittals and final state plan submittals. Multiple commenters requested the EPA provide state plan templates. One commenter requested templates for different plan designs (
CAA section 111(d)(1) requires the EPA to promulgate procedures “similar” to those in section 110 under which states adopt and submit CAA section 111(d) plans. The EPA has interpreted this provision previously in the implementing regulations found in 40 CFR part 60 subpart B. As discussed above, the EPA intends that planned revisions to the part 60 implementing regulations will clarify (among other things) whether certain procedures are appropriate for the EPA's action on CAA section 111(d) state plans, and if so, precisely how those procedures should apply. The EPA is proposing these revisions to the CAA section 111(d) implementing regulations in the notice of proposed rulemaking for the federal plan being issued concurrently with this final rule. In this section we discuss the legal basis for procedures that the EPA is finalizing in this action: Initial submittals, extensions, and plan revisions.
First, by using the ambiguous word “similar,” Congress delegated authority to the EPA to determine precisely what procedures would govern 111(d) plans. “Similar” does not have an identical meaning as the word “same.” One definition of “similar” is “having likeness or resemblance, especially in a general way.” The American College Dictionary 1127 (C.L. Barnhart, ed. 1970). On the other hand, “same” is defined as “alike in kind, degree, quality; that is, identical” or “unchanged in character.”
Had Congress intended that the procedures for section 111(d) plans be indistinguishable from those in section 110, Congress knew how to say so.
a.
Initial submittals in this instance are a reasonable gap-filling procedural step. As explained in our proposal, certain aspects of section 111(d) plan development for these particular guidelines warrant our creation of this procedural step, even though section 110 does not provide for initial submittals. As explained above, though, we are not bound under section 111(d)(1) to follow exactly the same procedures.
With respect to the timing of initial submittals, final submittals, and extensions, we note that section 111 does not prescribe any particular deadlines, instead leaving it to EPA's discretion to establish “similar” procedures to section 110. The implementing regulations for section 111(d) plans require state plans to be submitted within 9 months of finalization of emission guidelines. Section 110(a)(1) provides that states should adopt and submit SIPs that provide for implementation, maintenance, and enforcement of the NAAQS within 3 years, or such shorter period as the Administrator may prescribe.
Some commenters argued that the 1-year period for initial submittals and, even assuming an extension, the additional 1- to 2-year period for final submittals were unreasonably short, particularly in light of the possibility that some state legislatures might need to act to provide adequate legal authority for these particular plans. We are not finalizing the 1-year extension for single state submittals, and we have addressed concerns about legal authority for the initial submittals by allowing states to identify remaining legislative action in those submittals.
With respect to the overall period of up to 3 years for submittals, we continue to find it reasonable and consistent with other deadlines in the CAA. First, section 110(a)(1) requires states to submit a plan for implementation, maintenance, and enforcement of new NAAQS within 3 years of promulgation of that NAAQS. This is true even if the EPA promulgates a NAAQS for a previously non-criteria pollutant. In that case, it is possible and even likely that at least some state agencies will lack statutory authority to regulate the new pollutant. Nonetheless, Congress dictated that states should submit section 110(a)(1) plans within 3 years.
Furthermore, we note that under subpart 1 of Part D of Title 1, attainment plans are generally due no later than 3 years after designation of a nonattainment area, and under other subparts of Part D, plans are due even more quickly. For example, under subpart 4, attainment plans for particulate matter are generally due 18 months after designation, and under subpart 5, the same deadline applies for attainment plans for sulfur oxides, nitrogen dioxide and lead. Developing attainment plans may or may not require states to seek additional legislative authority, but certainly in terms of complexity they are similar to section 111(d) plans for this guideline. In general, attainment plans must contain (among other things) a comprehensive inventory of sources of the relevant pollutant and its precursors (which in populated areas can be very numerous), control measures for those sources (including individualized control measures for the larger sources), and modeled demonstrations of
b.
Section 110(l) provides for states to revise their SIPs, as does 40 CFR 60.28 for section 111(d) plans. Section 110(l) also sets out a standard for revisions: It prohibits the EPA from approving a SIP revision that would interfere with any applicable requirement concerning attainment or reasonable further progress, or any other applicable requirement of the CAA. Under the existing section 111(d) implementing regulations, the Administrator will disapprove section 111(d) plan revisions as unsatisfactory when they do not meet the requirements of subpart B to part 60. See 40 CFR 60.27(c)(3). However, the implementing regulations do not set forth a substantive standard like that in section 110(l).
Section 111(d)(1) does not mention revisions (except indirectly through the reference to section 110) and, therefore, does not explicitly provide any substantive requirements for them. There is, therefore, a gap in the statute that the EPA may reasonably fill, since many stakeholders commented on the desirability of states being able to modify their plans, and the EPA agrees. It is reasonable, at a minimum, that the state plan as revised should continue to provide for implementation and enforcement of the standards of performance, and to achieve the CO
In our proposal, we stated that certain revisions to state plans under these emission guidelines, those that revised enforceable measures for affected EGUs, should satisfy some additional conditions. First, the state should demonstrate that the plan continues to achieve the CO
It is also reasonable to tailor the requirements of the demonstration to the magnitude of the revision. The EPA has taken a similar approach to tailoring the requirements for a technical demonstration that, under section 110(l), a SIP revision does not interfere with any applicable requirement concerning attainment of the NAAQS. If a SIP revision does not relax the stringency of any SIP measure, then the demonstration is simple. If the SIP revision does relax the stringency of SIP measures, then a qualitative or quantitative analysis may be necessary to show non-interference, depending on the nature of the revision, the current air quality in the area, and other factors.
Finally, we proposed that revisions “should not result in reducing the required emission performance for affected EGUs specified in the original approved plan. In other words, no `backsliding' on overall plan emission performance through a plan modification would be allowed.” 79 FR 34917/1. We received adverse comments that this standard did not have a basis in section 111(d). According to commenters, since the standard for EPA approval of a section 111(d) plan is whether the plan is satisfactory in establishing and providing for implementation and enforcement of standards of performance that achieve the emission performance rates or goal, the same standard should apply to revisions. In other words, the standard for revisions should be whether the plan as revised is satisfactory. We believe that our proposal was unclear as to this point, and we agree that the standard for revisions should be the same as for submittals. We have finalized this position.
This section describes state plan requirements related to compliance periods, monitoring and reporting for affected EGUs; plan performance demonstrations; consequences if the CO
For plans that include emission standards on affected EGUs, the EGU emission standards for the interim period must have schedules of compliance for each interim step 1, 2 and 3 for the calendar years 2022-2024, 2025-2027 and 2028-2029, respectively. For the final period, EGUs must have emission standards that have schedules of compliance for each 2 calendar years starting in 2030 (
In the June 2014 proposal, the EPA proposed that the appropriate averaging time for any rate-based emission standard for affected EGUs be no longer than 12 months within a plan performance period and no longer than 3 years for a mass-based standard. The EPA solicited comments on longer and shorter averaging times for emission standards included in state plans. The EPA received comments stating that the proposed 12-month averaging was too short and that there was no reason why the compliance period under a rate-based plan should be different from a mass-based plan. Comments stated that a multi-year averaging period is appropriate for rate-based and mass-based plans to account for variations that can occur in a single year, allowing operators the flexibility they need to manage unforeseen events. The commenters also recommended that the final rule use discrete 3-year periods for compliance reconciliation instead of the rolling-average approach proposed.
The EPA has considered all comments received on this matter and is finalizing the compliance periods specified above, which respond to the comments by applying to both rate- and mass-based programs, providing compliance periods longer than 1 year, and establishing block compliance periods rather than a rolling average approach. We agree with comments that longer averaging periods allow for operational and seasonal variability to even out. The EPA finalizes that states can choose to set shorter compliance periods for their emission standards but none that are longer than the compliance periods the EPA is finalizing in this rulemaking. If a state chooses to set shorter compliance periods, we urge them to make efforts to be cognizant of other deadlines facing EGUs to assure that there will not be
State plans must contain requirements for tracking and reporting actual plan performance during implementation, which includes reporting of CO
In the June 2014 proposal, the EPA proposed that state plans must include monitoring, reporting and recordkeeping requirements for useful energy output from affected EGUs. Multiple commenters questioned whether gross rather than net electrical production should be reported by affected EGUs and recommended that the EPA should utilize gross rather than net generation. Many commenters recommended electricity be reported in the form used in the 111(b) rules for consistency between reporting requirements and simplification of calculation of emission limitations between new and old sources. Commenters also stated that to the extent the EPA seeks to provide guidance to states regarding its preferred monitoring and reporting procedures, the EPA should encourage states to avoid imposing additional monitoring and reporting burdens by taking advantage of the monitoring requirements that already exist to the greatest extent possible. For example, the commenters noted that the 40 CFR part 75 monitoring procedures used to comply with other programs, such as the Title IV Acid Rain Program, provide much of the data that would be needed to demonstrate compliance under the rule. Comments stated that the June 2014 proposal appeared to mandate a monitoring approach that would eliminate key flexibilities provided in the part 75 regulations, thus requiring utilities to maintain separate document collection and reporting procedures and potentially eliminating important alternative monitoring options intended to ensure representative, cost-effective monitoring approaches are available. The commenters asked the EPA to revise its proposal to make clear that the procedures established under part 75 will suffice or explain the need for any exceptions. Commenters indicated that the rule should require all affected EGUs to monitor CO
The state plan must include emission performance checks, and for state measures plans, periodic program implementation milestones. The state plan must provide for tracking of emission performance, and for measures to be implemented if the emission performance of affected EGUs in the state does not meet the applicable CO
As discussed above in section VII, the agency is finalizing CO
In 2032 and every 2 years thereafter, states must demonstrate that affected EGUs achieved the final performance rates or state goal on average or cumulatively, as appropriate, during each 2-year reporting period (
For a rate-based plan, emission performance is an average CO
For emission standards plans, as discussed in section VIII.D, the state must submit a report to the EPA containing the emissions performance comparison for each reporting period no later than the July 1 following the end of each reporting period (
The EPA notes that for certain types of emission standards plans, with mass-based emission standards in the form of an emission budget trading program, achievement of a state's mass-based CO
Also as discussed in section VIII.D, states that choose a state measures plan must submit an annual report no later than July 1 following the end of each calendar year in the interim period. This annual report must include the status of the implementation of programmatic state measures milestones identified in the state plan submittal. The annual report that follows the end of each reporting period (
In the June 2014 proposal, the EPA proposed that a state report is due to the EPA no later than July 1 of the year immediately following the end of each reporting period. The EPA requested comment on the appropriate frequency of reporting of the different proposed reporting elements, considering both the goals of minimizing unnecessary burdens on states and ensuring program effectiveness. In particular, the agency requested comment on whether full reports containing all of the elements should only be required every 2 years rather than annually and whether these reports should be submitted electronically, to streamline transmission.
The EPA mainly received adverse comments for requiring annual state reporting; commenters stated that this requirement was too burdensome for both states and the EPA. Commenters also requested that the EPA extend the due date of the annual report from July 1 to at least December 31. Commenters stated that because of the timing of current data collection and the need to leave time to organize and submit the reports, allowing only 6 months after the close of the year is problematic. Commenters asked that the EPA consider reducing the amount of data required if annual reporting was required.
Considering the comments received and the goals of minimizing unnecessary burdens on states and ensuring program effectiveness, the EPA has reduced the frequency of reporting of emissions data to every 3 years for the first two interim steps and every 2 years thereafter. However, the EPA is finalizing that state reports are due to the EPA no later than July 1 following the end of each reporting period. The EPA believes states can design their state plans to receive the data and information needed for these reports in a timely manner so that this requirement can be met. Furthermore, some of the state reporting requirements, such as reporting of EGU emissions, can be met through existing reporting mechanisms (ECMPS) and would not place additional burdens on states.
The EPA recognizes that, under certain scenarios, an approved state plan might fail to achieve a level of emission performance that meets the emission guidelines or the level of performance established in a state plan for an interim milestone. Despite successful implementation of certain types of plans, emissions under the plan could turn out to be higher than projected at the time of plan approval because actual conditions vary from assumptions used when projecting emission performance. Emissions also could theoretically exceed projections because affected entities under a state plan did not fulfill their responsibilities, or because the state did not fulfill its responsibilities.
The final rule specifies the consequences in the event that actual emission performance under a state plan does not meet, or is not on track to meet, the applicable interim and interim step CO
For emission standards plans, the final rule specifies that corrective measures must be enacted once triggered. Corrective measures apply
When corrective measures are triggered, if the state plan does not already contain corrective measures, the state must submit to the EPA a plan revision including corrective measures that adjust requirements or add new measures. The corrective measures must both ensure future achievement of the CO
For states using the state measures approach, the EPA is finalizing the backstop requirement as described in section VIII.C.3 of this preamble. As discussed in section VIII.D.2, the determination that a state using the state measures approach is not on track to meet the applicable interim goal or interim step goals in 2022-2029, or the applicable final goal in 2030-2031 or later, is based on checks that must be included in state reports that must be submitted annually during the interim period and biennially during the final period. The state must annually report on its progress in meeting its programmatic state measures milestones during the interim period. In addition, the state must report actual emission performance checks, similar to the requirements discussed above for emission standards plans, in 2025, 2028, 2030, and every 2 years thereafter. If, at the time of the state report to the EPA, the state did not meet the programmatic state measures milestones for the reporting period, or the performance check shows that the plan's actual CO
For multi-state plans, corrective measure or backstop provisions would be required for the same plan approaches for which those provisions are required in individual state plans. For multi-state plans using plan approaches to which corrective measures or backstop requirements apply, all states that are party to the multi-state plan would be subject to corrective action or backstop requirements, and requirements to make up the past CO
Multiple commenters requested that corrective measures not be required in the case of a catastrophic, uncontrollable event. We recognize that there are potential system emergencies that cannot be anticipated that could cause a severe stress on the electricity system for a length of time such that the multi-year requirements in a state plan may not be achievable by certain affected EGUs without posing an otherwise unmanageable risk to reliability. We are finalizing a reliability safety valve, which includes an initial period of up to 90 days during which a reliability-critical affected EGU or EGUs will not be required to meet the emission standard established for it under the state plan but rather will meet an alternative standard. While the initial 90-day period is in use, the emissions of the affected EGU or EGUs that exceed their obligations under the approved state plan will not be counted against the state's overall goal or emission performance rate for affected EGUs and will not be counted as an exceedance that would otherwise trigger corrective measures under an emission standard plan type or an exceedance that would trigger a backstop under a state measures plan type. Use of the reliability safety valve will not alter or abrogate any other obligations under the approved state plan. After the initial period of up to 90 days, the reliability-critical affected EGU is required to continue to operate under the original state plan emission standard or an alternative standard as part of the
Multiple commenters supported the inclusion of strong enforcement measures for ensuring the interim and final goals are met, including the required use of corrective measures when triggered. Other commenters provided feedback as to the percentage that actual emission performance would need to exceed the level of emission performance specified in the statewide plan to trigger corrective measures. Some commenters supported the trigger that we are finalizing (actual emissions or emission rate performance that is 10 percent or more than the specified level of emission performance in the state plan for the interim step 1 or step 2 performance periods), while some recommended a lower or higher trigger.
The agency is finalizing the trigger at the level of 10 percent for the interim step 1 or step 2 performance periods. Ten percent is a reasonable level to ensure that when deficiencies in state plan performance begin to emerge, corrective measures (or backstop requirements) will be implemented promptly to avoid emissions shortfalls (or minimize the extent of shortfalls) relative to the 8-year interim goal and the final goal, which reflect the BSER. The 10 percent figure also provides latitude for a state's emission improvement trajectory during the interim period to deviate a bit from its planned path without triggering these requirements, as the state initiates or ramps up programs to meet the 8-year interim goal and final goal.
The EPA requested comment on whether the agency should promulgate a mechanism under CAA section 111(d) similar to the SIP call mechanism in CAA section 110. Under this approach, after the agency makes a finding of the plan's failure to achieve the CO
The EPA intends that planned revisions to the part 60 implementing regulations will clarify (among other things) whether the EPA has authority to call for plan revisions under section 111(d) when a state's plan is not complying with the requirements of this guideline, and if so, precisely what procedures should apply. The EPA is proposing these revisions to the 111(d) implementing regulations in the notice of proposed rulemaking for the federal plan. The EPA is not taking final action now on this issue or the related change to the implementing regulations.
a.
The EPA discussed the concept of corrective measures in our 1992 General Preamble for the Implementation of Title I of the CAA Amendments of 1990. 57 FR 13498 (Apr. 16, 1992). The General Preamble sets out four general principles that apply to all SIPs, “including those involving emissions trading, marketable permits and allowances.”
Some commenters noted that the contingency measures explicitly required by part D are required to be adopted in the attainment plan and ready to implement when a milestone is not achieved or the area fails to attain the relevant NAAQS. These commenters therefore concluded that corrective measures for 111(d) plans should likewise already be adopted in the 111(d) plan and ready to implement. We disagree. Under Part D, contingency measures are not expected to fully bring the area into attainment. In fact, this would not be possible given the difficulty of predicting in advance exactly what measures would be needed to fully attain. A better analogue in Part D for the corrective measures in these guidelines is the primary way Part D addresses failure to attain: The state is required to revise its plan in various ways within a certain time in order to bring about attainment. See,
However, the requirement to revise an attainment plan in response to failure to attain differs somewhat from the corrective measures in these guidelines. Under these guidelines, the corrective measures must make up the difference by which the plan fell short of the goal, including any prior shortfall that had accumulated if the plan fell short of the goal in prior years. There is no corresponding requirement in attainment planning to increase the stringency of the plan by an amount that somehow makes up for any shortfall in attainment from prior years; instead the revised plan must demonstrate attainment going forward, and other more stringent requirements (such as requirements for best available control measures) may be triggered.
This distinction is the natural result of the difference between these guidelines and NAAQS attainment planning. In this case, we are finalizing guidelines representing technology-based standards for a pollutant with cumulative and long-lasting effects. If a plan falls short of a performance goal, then in effect the standards of performance in the plan have failed to reflect the BSER over the corresponding period. Due to the cumulative effects of CO
Some commenters noted that 111(d) does not contain explicit provisions regarding corrective measures, and they therefore inferred that the EPA is not authorized to require them. That inference is mistaken. The requirement for 111(d) plans to “provide for implementation and enforcement” of the standards of performance is ambiguous and does not directly speak to whether corrective measures should or should not be required. There is therefore a gap for the EPA to fill. While the discussion above about Part D does not independently provide any authority to fill this gap, the fact that Congress created a scheme with stages of planning in Part D suggests that it would be reasonable, if appropriate, to fill this gap in 111(d) in a similar way.
In this guideline, it is appropriate for emission standards plans to fill this gap with corrective measures if triggered. There are two ways an emission standards plan can provide for implementation of standards of performance that achieve the CO
The agency is determining CO
As noted above, the state plan must demonstrate that plan measures are projected to achieve the final emission performance level by 2030. In addition, the state plan must identify requirements that continue to apply after 2030 and are likely to maintain affected EGU emission performance meeting the final goal. The state plan would be considered to provide for maintenance of emission performance consistent with the final goal if the plan measures used to demonstrate projected achievement of the final goal by 2030 will continue in force and not sunset. After implementation, the state is required to compare actual plan performance against the final goal on a 2-year average basis starting in 2030, and to implement corrective measures or a backstop if triggered.
In the proposal, the EPA noted that “CAA section 111(b)(1)(B) calls for the EPA, at least every eight years, to review and, if appropriate, revise federal standards of performance for new sources” in order to assure regular updating of performance standards as technical advances provide technologies that are cleaner or less costly. The proposal “requests comment on the implications of this concept, if any, for CAA section 111(d).” 79 FR 34830, 34908/3 (June 18, 2014).
We acknowledge the obligation to review section 111(b) standards as stated. The EPA is not finalizing any position with respect to any implications of this concept for section 111(d). We are promulgating rules for section 111(d) state plans that will establish standards of performance for existing sources to which a section 111(b) standard of performance would apply if such sources were new sources, within the definition in section 111(a)(2) of “new source.” It is not necessary to address at this time whether subsequent review and/or appropriate revision of the corresponding section 111(b) standard of performance have any implications for review and/or revision of this rule.
a.
In the proposal, the EPA proposed “that the level of emission performance for affected EGUs represented by the final goal should continue to be maintained.” The EPA explained that “Congress either intended the emission performance improvements required under CAA section 111(d) to be permanent or, through silence, authorized the EPA to reasonably require permanence. Other CAA section 111(d) emission guidelines set emission limits to be met permanently.” 79 FR 34830, 34908/2 (June 18, 2014). We also requested comment on whether “we should establish BSER-based state performance goals that extend further into the future (
We received adverse comment on establishing BSER-based state performance goals beyond the proposed planning period. Commenters argued that we did not have a sufficient basis at this time to determine what those future goals should be. We agree and have decided not to establish such goals. We are finalizing, though, that the level of emission performance for affected EGUs represented by the final goal should continue to be maintained, for the reasons given in our proposal and quoted above.
The general structure of the CAA supports our interpretation. Section 111(d) plans establish standards of performance that reflect the BSER, a technology-based standard. Generally speaking, in the future technology will only improve, and correspondingly the CAA does not provide explicit processes to relax technology-based standards. In contrast, the provisions in Part D of title I that address attainment of health-based standards, the NAAQS, explicitly provide that once the NAAQS are attained, emission reduction measures may be relaxed so long as the NAAQS are maintained. The absence in section 111(d) of explicit provisions for future relaxation of emission reduction measures, as compared to Part D, supports our interpretation that the emission reductions continue to be on-going after the CO
This section discusses the way in which the final emission guidelines address the CAA section 111(d)(1)
The final guidelines permit a state, in developing its state plan, to fully consider and take into account the remaining useful life of an affected EGU and other factors in establishing the requirements that apply to that EGU, as discussed further below. Therefore, consideration of facility-specific factors and in particular, remaining useful life, does not justify a state making further adjustments to the performance rates or aggregate emission goal that the guidelines define for affected EGUs in a state and that must be achieved by the state plan. Thus, these guidelines do not provide for states to make additional goal adjustments based on remaining useful life and other facility-specific factors because they can fully consider these factors in designing their plans.
a.
This section describes the statutory and existing regulatory background concerning facility-specific considerations in implementation of section 111(d).
Section 111(d)(1)(A) requires states to submit a plan that “establishes standards of performance” for existing sources. Under section 111(d)(1)(B), the plan must also “provide for implementation and enforcement of such standards of performance.” Finally, the last sentence of section 111(d)(1) provides: “Regulations of the Administrator under this paragraph shall permit the State in applying a standard of performance to any particular source under a plan submitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.”
The EPA's 1975 implementing regulations
(1) Unreasonable cost of control resulting from plant age, location, or basic process design;
(2) Physical impossibility of installing necessary control equipment; or
(3) Other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable.
This provision was amended in 1995 (60 FR 65387, December 19, 1995), and is now prefaced with the language “Unless otherwise specified in the applicable subpart on a case-by-case basis for particular designated facilities or classes of facilities.” 40 CFR 60.24(f).
b.
Our proposal stated that the reference to “[u]nreasonable cost of control resulting from plant age” in 60.24(f) “implements” the statutory provision on remaining useful life. We also stated that the implementing regulations “provide the EPA's default structure for implementing the remaining useful life provision of CAA section 111(d).” We noted that the prefatory language “unless otherwise specified in the applicable subpart” gives the EPA discretion to alter the extent to which the implementing rules applied if appropriate for a particular source category and guidelines. We requested comment on our analysis of the existing implementing regulations and any implications for our regulatory text in respect to how these guidelines relate to those regulations.
Commenters stated, among other things, that the sentence concerning “remaining useful life” was added in the 1977 CAA Amendments and that therefore it could not be said that provisions from the 1975 implementing regulations “implement” the sentence. The EPA does not think as a general matter that it is necessarily impossible that a pre-statutory amendment rule could continue to serve as a reasonable implementation of a post-statutory amendment provision. However, we also think it is appropriate, as we suggested in the June 2014 proposal, to specify in the applicable subpart for these guidelines that the provisions in 60.24(f) should not apply to the class of facilities covered by these guidelines. As a result, regardless of whether the implementing regulations appropriately implement the “remaining useful life” provision in general, the relevant consideration is that, as we now explain, these particular guidelines “permit the State in applying a standard of performance to any particular source under a plan submitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.”
c.
The EPA notes that, in general, the implementing regulation provisions for remaining useful life and other facility-specific factors are relevant for emission guidelines in which the EPA specifies a presumptive standard of performance that must be fully and directly implemented by each individual existing source within a specified source category. Such guidelines are similar to a CAA section 111(b) standard in their form. For example, the EPA emission guidelines for sulfuric acid plants, phosphate fertilizer plants, primary aluminum plants, Kraft pulp plants, and municipal solid waste landfills specify emission limits for sources.
In these final guidelines for state plans to limit CO
The guidelines capitalize on the inherent flexibility offered by the CO
In addition to providing states with flexibility on the form of the standards of performance in their plans, the guidelines leave to each state the design of the specific requirements that fall on each affected EGU in applying those standards. To the extent that an emission standard that a state may wish to adopt for affected EGUs raises facility-specific issues, the state may make adjustments to a particular facility's requirements on facility-specific grounds, so long as any such adjustments are reflected (along with any necessary compensating emission reductions to meet the state goal) in the state's CAA section 111(d) plan submission.
Finally, we note that these guidelines permit states to use a rate or mass CO
The EPA believes that this approach to permitting states to consider remaining useful life is appropriate because it reflects, and is compatible with, the interconnected nature of the electricity system.
Although this discussion emphasizes state flexibility on plan design, it is important to note that the main intended beneficiaries of state flexibility are the affected EGUs themselves. As a key case in point, the EPA has endeavored to craft the final guidelines to support and facilitate state plans that include trading systems, including interstate trading systems that can help EGUs continue to operate with the flexibility that they currently enjoy on regional grid levels.
Trading can provide affected EGUs that have a limited remaining useful life with the flexibility to comply through purchasing allowances or ERCs, thereby avoiding major capital expenditures that would create long-term debt. By buying allowances or ERCs, affected EGUs with a limited remaining useful life contribute to achieving emission reductions from the source category during the years that they operate. During its lifetime, a facility with a short remaining useful life will need fewer total credits or allowances than an otherwise comparable facility with a long remaining useful life, but the annualized cost to the two facilities is the same.
In part to help states address remaining useful life considerations, the final guidelines facilitate state plans that employ trading in multiple ways:
• By allowing trading under emission standards plans and state measures plans, and under rate-based plans and mass-based plans;
• By defining national EGU performance rates that make it easier for states to set up rate-based trading regimes that allow for interstate trading of ERCs;
• By clearly defining the requirements for mass-based and rate-based trading systems to ensure their integrity; and
• By providing information on potential allocation approaches for mass-based trading.
In addition, the EPA is separately proposing model trading rules for rate-based and mass-based trading to assist states with design of these programs in the section 111(d) context.
d.
Under the final guidelines, remaining useful life and other facility-specific considerations do not provide a basis for adjusting the CO
As noted above, the final guidelines provide aggregate emission goals for affected EGUs in each state, in addition to the CO
To be more specific, the EPA notes that a state is not required to achieve the same level of emission reductions with respect to any one building block as assumed in the EPA's BSER analysis. A state may use any combination of measures, including those not specifically factored into the BSER by the EPA. The EPA has estimated reasonable rather than maximum possible implementation levels for each building block in order to establish EGU emission rates and state goals that are achievable while allowing states to take advantage of the flexibility to pursue some building blocks more aggressively, and others less aggressively, than is reflected in the agency's computations, according to each state's needs and preferences. The guidelines provide further flexibility by allowing state plans to use emission reduction methods not reflected in the BSER. A description of multiple emission reduction methods is provided in sections VIII.I-K.
e.
In response to the proposed guidelines, some commenters said that the proposed state goals were
In the final guidelines, the EPA has addressed the comments about lack of practical flexibility to consider remaining useful life by revising key elements of the guidelines in ways that will ensure that the CO
The changes to the BSER and goal-setting methodologies include:
The final guidelines also contain changes to avoid certain inconsistencies between the goal-setting methodology and accounting of reductions under state plans that could have made state goals less achievable for some states.
Together, the changes described above help to ensure that the CO
As explained in the Legal Memorandum accompanying this rule, the EPA believes that Congress intended the remaining useful life provision to provide a mechanism for states to avoid the imposition of unreasonable retrofit costs on existing sources with relatively short remaining useful lives, a scenario that could result in stranded assets. However, commenters on the proposed rule raised a different stranded assets concern not primarily related to retrofit costs—a concern that the proposed rule could cause changes in economic competitiveness of particular EGUs that would prompt their retirement before the end of their economically useful lives. These commenters said the proposed state goals were so stringent that states would have no choice but to adopt requirements that would result in retirements of coal-fired capacity that had been built relatively recently or had recently made pollution control investments. In response to these comments, the EPA has conducted a stranded assets analysis which demonstrates that the CO
For purposes of the stranded assets analysis, the EPA considered a potential “stranded asset” to be an investment in a coal-fired EGU (or in a capital-intensive pollution control installed at such an EGU) that retires before it is fully depreciated. Book life is the period over which long-lived assets are depreciated for financial reporting purposes. The agency estimated typical book life by researching financial statements of utility and merchant generation companies in filings to the Securities and Exchange Commission. The agency estimated the book life of coal-fired EGUs to be 40 years, and assumed a 20-year book life for pollution control retrofits. The book life of coal-fired EGUs (coal steam and IGCC) is twice as long as the debt life and the depreciation schedule used for federal tax purposes. Although the book life for environmental retrofits is often 15 years, the agency conservatively assumed 20 years in this analysis.
The analysis examined coal generation in the three large regional interconnections of the U.S. The analysis found that in both 2025 and 2030, for each region, the amount of 2012 coal generation included in the final guidelines' emission performance rate calculation—specifically, the generation remaining after the BSER calculation—is greater than the amount of 2012 generation from coal-fired EGUs that are not fully depreciated in those years under the book life assumptions described above. This shows that the final rule allows flexibility for states to preserve these units as part of their plans.
To put this analysis in perspective: The EPA's role is to set emission guidelines that meet the statutory requirements, which includes consideration of cost in identifying the BSER, as the EPA has done in these guidelines. States have a broad degree of flexibility to design plans to achieve the rates in the emission guidelines in a manner that meets their policy priorities, including ensuring cost-effective compliance. Although not a required component of the EPA's consideration of cost, this analysis shows that the CO
Several commenters said that the statute does not authorize the EPA to require other facilities to achieve greater reductions to compensate for a facility that warrants relief based on remaining useful life. One said that consideration of remaining useful life and other relevant factors is a one-way ratchet that provides relief to sources that cannot achieve the BSER, and that the EPA turns that approach on its head by prohibiting a state from providing such relief to a specific facility unless it can identify another facility to “punish” by requiring additional emissions reductions to offset that relief.
The EPA disagrees with these comments, which proceed from an incorrect premise. The EPA is not determining a BSER-based emission level achievable by each individual facility without trading, and then
An additional reason that the EPA believes that consideration of remaining useful life and other facility-specific factors does not warrant adjustments to state goals is that the design of the guidelines does not mandate that states impose requirements that would call for substantial capital investments at affected EGUs late in their useful life. Multiple methods are available for reducing emissions from affected EGUs that do not involve capital investments by the owner/operator of an affected EGU. For example, generation shifts among affected EGUs, and addition of new RE generating capacity do not generally involve capital investments by the owner/operator at an affected EGU. Additional emission reduction methods available to states that do not entail significant capital costs at affected EGUs are discussed elsewhere in this preamble.
Heat rate improvements at affected EGUs may require capital investments. However, states have flexibility to design their plan requirements; they are not required to mandate heat rate improvements at plants that have limited remaining useful life. In fact, a state can choose whether or not to require heat rate improvements at all. The agency also notes that capital expenditures for heat rate improvements would be much smaller than capital expenditures required for example, for purchase and installation of scrubbers to remove SO
Remaining useful life and other factors, because of their facility-specific nature, are potentially relevant as states determine requirements that are directly applicable to affected EGUs. If relief is due a particular facility, the state has an available toolbox of emission reduction methods that it can use to develop a section 111(d) plan that will achieve the CO
f.
Section 111(d)(1) only requires that EPA emission guidelines permit states to take into account remaining useful life (among other factors), but section 111(d)(1) does not specify how the EPA must permit that. In other words, the meaning of the provision and the way that the EPA is to implement it in promulgating guidelines are not specified further in the provision. The provision is ambiguous and capable of implementation in several ways, and therefore the EPA has discretion to interpret and apply it. Furthermore, section 111(d)(1) does not suggest that states must be given carte blanche to consider remaining useful life in any way that can be imagined. As detailed above in sections VIII.G.1.c-e, these guidelines permit states to take into account remaining useful life in a number of reasonable ways and thus the guidelines satisfy the statutory obligation.
The phrase “remaining useful life” also appears in the visibility provisions of section 169A. There, in determining best available retrofit technology (BART), the state (or the EPA) must take into consideration (among other factors) “the remaining useful life of the source.” 42 U.S.C. 7491(g)(2); see also
Although section 111(d)(1) is different than section 169A(g)(2) and need not be interpreted in the same way, we would note (as discussed in detail in sections VIII.G.1.c-e, section 5.11 of the Response to Comments document, and the Legal Memorandum) that (for
Some commenters stated that the EPA's interpretation of remaining useful life is impermissible. These commenters claimed that states, if they wish to take into account remaining useful life at one affected EGU, must relax the stringency of the emission standard for that EGU. Then, the state would be compelled to increase the stringency of emission standards at other affected EGUs in order to achieve the state performance goal. According to these commenters, section 111(d) does not allow this outcome.
First, the commenters are mistaken in their premise. As discussed in section VIII.G.1, section 5.11 of the Response to Comments document, the Legal Memorandum, and in the example immediately above, states can impose the exact same emission standards on two affected EGUs and still take into account remaining useful life through the availability of trading. In other words, states need not relax an emission standard here and strengthen an emission standard there in order to take into account remaining useful life. Thus, these guidelines permit states to take into account remaining useful life without any of the effects commenters are concerned about.
Second, even if states decide to relax emission standards at one EGU, on the basis of remaining useful life or any other factor, nothing in the last sentence of section 111(d)(1) prohibits these guidelines from requiring the state plan to still meet the CO
The final rule features overall flexibility, a long planning and implementation horizon, and a wide range of options for states and affected EGUs to achieve the CO
As discussed throughout the preamble and TSDs, the electricity sector is undergoing a period of intense change. While the change in the resource mix has accelerated in recent years, wind, solar, other RE, and EE resources have been reliably participating in the electric sector for a number of years. Many of the potential changes to the electric system that the final rule may encourage, such as shifts to cleaner sources of power and efforts to reduce electricity demand, are already well underway in the electric industry. To the extent that the final rule accelerates these changes, there are multiple features well embedded in the electricity system that ensure that electric system reliability will be maintained. Electric system reliability is continually being considered and planned for. For example, in the Energy Policy Act of 2005, Congress added a section to the Federal Power Act to make reliability standards mandatory and enforceable by FERC and the North American Electric Reliability Corporation (NERC), the Electric Reliability Organization which FERC designated and oversees. Along with its standards development work, NERC conducts annual reliability assessments via a 10-year forecast and winter and summer forecasts; audits owners, operators, and users for preparedness; and educates and trains industry personnel. Numerous other entities such as FERC, DOE, state PUCs, ISOs/RTOs, and other planning authorities also consider the reliability of the electric system. There are also numerous remedies that are routinely employed when there is a specific local or regional reliability issue. These include transmission system upgrades, installation of new generating capacity, calling on demand response, and other demand-side actions.
Additionally, planning authorities and system operators constantly consider, plan for, and monitor the reliability of the electricity system with both a long-term and short-term perspective. Over the last century, the electric industry's efforts regarding electric system reliability have become multidimensional, comprehensive, and sophisticated. Under this approach, planning authorities plan the system to assure the availability of sufficient generation, transmission, and distribution capacity to meet system needs in a way that minimizes the likelihood of equipment failure.
As the electricity market changes and new challenges emerge, electric system regulators and industry participants make changes to how the electric system is designed and operated to respond to these challenges. For example, expressing reliability and rate concerns about fuel assurance issues, FERC recently issued an order requiring ISOs/RTOs to report on the status of their efforts to address market and system performance associated with fuel assurance.
The EPA's approach in this final rule is consistent with our commitment to ensuring that compliance with the final rule does not interfere with the industry's ability to maintain the reliability of the nation's electricity supply. Many aspects of the final rule's design are intended to support system reliability, especially the long compliance period and the basic design that allows states and affected EGUs flexibility to include a large variety of approaches and measures to achieve the environmental goals in a way that is tailored to each state's and utility's energy resources and policies. Despite the flexibility built into the design of the proposal, and the long emission reduction trajectory, many commenters expressed concerns that the proposed rule could jeopardize electric system reliability. We note that the EPA has received similar comments in EPA rulemakings dating as far back as the 1970s. The EPA has always taken and continues to take electric system reliability comments very seriously. These reoccurring comments with regard to reliability notwithstanding, the electric industry has done an excellent job of maintaining reliability, including when it has had to comply with environmental rules with much shorter compliance periods and much less flexibility than this final rule provides. Now, more than ever, the electric industry has tools available to maintain reliability, including mandatory and enforceable reliability standards.
As with numerous prior CAA regulations affecting the electric power sector, environmental requirements for this industry are accommodated within the existing extensive framework established by federal and state law to ensure that electricity production and delivery are balanced on an ongoing basis and planned sufficiently to ensure reliability and affordability into the future. In addition, changes that the EPA is making in this final rule respond directly to the comments and the suggestions that we received on reliability and provide further assurance that implementation of the final rule will not create reliability concerns.
First, the final rule allows significant flexibility in how the applicable CO
Second, the final rule provides sufficient time to ensure system reliability. The final rule retains the 2030 date for the final period, which commenters largely supported as reasonable and not a concern for reliability, and addresses one of the key issues that commenters pointed to as a reliability-related concern by both moving the start of the interim period from 2020 to 2022 and adjusting the interim goals to provide a more gradual phasing-in of the initial reduction requirement and thus a more gradual emissions reduction trajectory or glide path to the final 2030 goals. These changes deliver on the intent of the proposal to afford states and affected EGUs the latitude to determine their own emissions reduction schedules over the interim period. Both FERC's May 15, 2015 letter
As a result of these changes, the states themselves will have a meaningful opportunity—which, again, many commenters suggested the timing and stringency of the proposal failed to create despite our intent to do so—to determine the timing, cadence and sequence of actions needed for states and sources to meet final rule requirements while accommodating the ongoing activity needed to ensure system reliability. The final rule provides more than 6 years before reductions are required and an 8-year period from 2022 to 2029 to meet interim goals. Moreover, while the final rule requires each state to submit a plan by September 6, 2016, we recognize that some states may need more than 1 year to complete all of the actions needed for their final state plans, including
Third, we are including in the final rule a requirement that each state demonstrate in its final state plan submittal that it has considered reliability issues in developing its plan. This was suggested by a number of commenters, and we agree that it is a useful element to state plan development.
Fourth, the final rule provides a mechanism for a state to seek a revision to its plan in order to address changes in circumstances that could have reliability impacts if not accommodated in the plan. The long compliance timeframe, with several interim steps, naturally provides opportunities for states, working with their utilities and reliability entities, to assess how implementation is proceeding, identify unforeseen changes that may warrant plan revisions, and work with the EPA to make necessary revisions. Similarly, the ready availability of emissions trading as a compliance tool affords EGUs ample flexibility to integrate compliance with both routine and critical reliability needs.
Fifth, in response to a variety of comments, we are providing a reliability safety mechanism that provides a path for a state to come to the EPA during an immediate, unforeseen, emergency situation that threatens reliability to notify the EPA that an affected EGU or EGUs may need to temporarily comply with modified emission standards to respond to this kind of reliability concern.
Sixth and finally, we are committed to maintaining an ongoing relationship with FERC and DOE as this final rule is implemented to help ensure continued reliable electric generation and transmission.
We provide more details about these various elements of the final rule, as well as other features of the rule that support system reliability, below.
a.
The EPA received a number of comments regarding the proposed rule and electric reliability. Many commenters provided specific, useful ideas regarding changes that could be made to the proposal to specifically address their reliability concerns. For example, many commenters state that allowing additional time to comply could help in meeting the final rule requirements while addressing their reliability concerns. Some commenters suggest that additional time would allow them to evaluate potential reliability impacts and system changes that need to be made to comply with final rule requirements while allowing affected EGUs time to meet interim CO
b.
In issuing this final rule, the EPA considered public comments on the potential interaction between the proposal and electric reliability. While we have made every effort to develop guidelines that would allow states and utilities to steer clear of potential reliability disruptions, a number of commenters argued that the possibility of an unanticipated reliability event cannot be entirely eliminated. It is important to note that there are many factors that influence system reliability and, given the complexity of the electric grid, electric system planners and operators likely will not completely avoid reliability issues, even in the absence of these guidelines. The EPA designed the final rule to ensure to the greatest extent possible that actions taken by states and affected EGUs to comply with the final rule do not increase potential reliability issues or complicate their resolution. In fact, to the extent that meeting final rule requirements results in the reduction of demand, upgrades in transmission efficiency and infrastructure, and investment in new, more efficient technologies, the outcome could be that the system is more robust and faces fewer risks to electric reliability.
One specific concern raised by many commenters is that the proposed plan development schedule may not leave sufficient time to conduct reliability planning between the development of state plans and the proposed start of the interim period in 2020. To address these concerns and to support a more effective reliability planning process, the EPA is moving the start of the interim period from 2020 to 2022 and adjusting the interim goals to provide a gradually phased-in initial reduction requirement and a more gradual glide path to the final 2030 goals. This more gradual application of the BSER over the 2022-2029 interim period provides the state with substantial latitude in selecting the emission reduction glide path for affected EGUs over that period. As noted above, the final rule also provides states with up to 3 years to adopt and submit their final state plans, and afterwards states can, if necessary, revise their plans, as discussed in section VIII.E.7. This timing gives system planners and operators the opportunity to do what they have already been doing; looking ahead to forecast potential contingencies that pose reliability risks and identifying those actions needed to mitigate those risks. The final rule allows states to develop a pathway over the interim period that reflects their own circumstances, such as reflecting planned additions and changes in generation mix and potentially taking advantage of opportunities for trading of credits or allowances by affected EGUs within and between states. Because achievement of the emission rates or goals can be demonstrated over several years, state plans can accommodate situations where, for example, it may take time to develop new generation, pipelines, or transmission while still providing many options for meeting the final rule requirements and planning for the reliability of the system.
c.
Under CAA section 111(d)(1)(B), state plans must provide for the implementation and enforcement of standards of performance for affected EGUs. The EPA does not believe a state that establishes standards of performance for affected EGUs without taking reliability concerns into consideration satisfactorily provides for the implementation of such standards of performance as required by CAA section 111(d)(1)(B), as a serious reliability issue would disrupt the state's provision
A number of commenters, notably ISOs and RTOs, also discussed reliability concerns in the context of state plans and pointed out that planning and anticipation of change are among the essential ingredients of ensuring the ongoing reliability of the electricity system. To that end, they recommended that as states are developing state plans, their activity include the consideration of the reliability needs of the region in which affected EGUs operate and of the potential impact of actions to be taken in compliance with state plans. Therefore, we are requiring that each state demonstrate in its final state plan submittal that it has considered reliability issues in developing its plan. One particularly effective way in which states can make this demonstration is by consulting with the relevant ISOs/RTOs or other planning authorities as they develop their plans and documenting this consultation process in their state plan submissions. If a state chooses to consider reliability through consultation with the ISO/RTO or other planning authority, the EPA recommends that the state request that the planning authority review the state plan at least once during the plan development stage and provide its assessment of any reliability implications of the plan. Additionally, we encourage states that are considering reliability through an ISO/RTO or other planning authority consultation process to have a continuing dialogue with those entities during development of their final state plan. While following the recommendations of the planning authority would not be mandatory, the state should document its consultation process, any response and recommendations from the planning authority, and the state's response to those recommendations in its final state plan submittal to the EPA. This consultation is designed to inform how the state might adjust its plan for meeting the CO
d.
If, during the implementation of a state plan, a reliability issue cannot be addressed within the range of actions or mechanisms encompassed in an approved state plan, the state can submit a plan revision to the EPA to amend its plan. In such a circumstance, the state plan may need to be adjusted to enable affected EGUs to continue to meet final rule requirements without causing an otherwise unmanageable reliability threat. In all cases the plan revision must still ensure the affected EGUs meet the emission performance level set out in the 111(d) final rule. Whether or not these circumstances occur will depend in part upon how each state designs its state plan. States that design plans with a high level of flexibility, such as market-based plans or multi-state plans, are less likely to face a potential conflict between state plan requirements and the maintenance of reliability. States that participate in multi-state programs will be better able to weather unexpected reliability risks.
Events not anticipated at the time of the final plan submittal—such as the retirement of a large low- or zero-emitting unit—may trigger the request for state plan revisions. It may also be the case that affected EGU-specific emission standards in a state plan are proving to be too inflexible to allow the plan to accommodate market or other changes in the power sector. In such instances, there should be a lead time between the announced retirement of the unit and the need to amend the state plan. Therefore, the state should be able to utilize the revisions process that the EPA provides.
The EPA will review a plan revision per the implementing regulation requirements of 40 CFR part 60.28. If the state's request for a state plan revision must be addressed in an expedited manner to assure a reliable supply of electricity, the state must document the risks to reliability that would be addressed by the plan revision by providing the EPA with a separate analysis of the reliability risk from the ISO/RTO or other planning authority. This analysis should be accompanied by a statement from the ISO/RTO or other planning/reliability authority that there are no practicable alternative resolutions to the reliability risk. In this case, the EPA will conduct an expedited review of the state plan revision.
e.
In this section we describe a reliability safety valve, available to states with affected EGUs providing reliability-critical generation in emergency circumstances. Specifically and as discussed below the reliability safety valve provides i) a 90-day period during which the affected EGU will not be required to meet the emission standard established for it under the state plan but rather will meet an alternative standard, and ii) a period beginning after the initial 90 days during which the reliability-critical affected EGU may be required to continue to operate under an alternative standard rather than under the original state plan emission standard, as needed in light of the emergency circumstances, and the state must during this period revise its plan to accommodate changes
Many commenters expressed concerns that a serious, unforeseen event could occur during the final rule implementation period that would require immediate reliability-critical responses by system operators and affected EGUs that would result in unplanned or unauthorized emissions increases. After reviewing the comments, we believe that it is highly unlikely that there would be a conflict between activities undertaken under an approved state plan and the maintenance of electric reliability, except in the case of a state plan that puts relatively inflexible requirements on specific EGUs. While some have pointed out that severe weather or other short-term events could potentially conflict with state plans, we note that most of those events are of short duration and would not require major—if any—adjustments to emission standards for affected EGUs or to state plans. For example, during an event like the extreme cold experienced in periods of the winter of 2013-2014, affected EGUs may need to run at a higher level for a short period of time to accommodate increased demand and/or short-term unavailability of other generators. However, because compliance by affected EGUs will be demonstrated over 2-3 years, such a short-term event would not cause affected EGUs to be out of compliance with their applicable emission standards. States can also ensure that this is true by developing plans that allow adequate compliance flexibility to accommodate such short-term events. We note that we have included in this final rule a number of different features designed to facilitate emissions trading between and among EGUs on an interstate basis—and have done so, in no small part, in response to comments from states and stakeholders seeking to put in place or operate under state-level and interstate emissions trading regimes. Affected EGUs operating in those circumstances and operating, in addition, subject to state plans that incorporate flexible glide paths and trading would be able to accommodate an unanticipated reliability event.
We recognize, however, that affected EGUs operating in a state with a relatively inflexible state plan could face unanticipated system emergencies that could cause a severe stress on the electricity system for a length of time such that the requirements in that state's plan may not be achievable by certain affected EGUs without posing an otherwise unmanageable risk to reliability. In particular, there could be extremely serious events, outside the control of affected EGUs, that would require an affected EGU or EGUs operating under an inflexible state plan to temporarily operate under modified emission standards to respond to this kind of reliability concern. Examples of such an event could include, a catastrophic event that damages critical or vulnerable equipment necessary for reliable grid operation; a major storm that floods and causes severe damage to a large NGCC plant so that it must shut down; or a nuclear unit that must cease generating unexpectedly and therefore other affected EGUs need to run so as to exceed their requirements under the approved state plan. This is not an all-inclusive list, but the examples illustrate several key attributes of the kinds of circumstances in which the reliability safety valve would apply. First, the event creating the reliability emergency would be unforeseeable, brought about by an extraordinary, unanticipated, potentially catastrophic event. Second, the relief provided would be for EGUs compelled to operate for purposes of providing generation without which the affected electricity grid would face some form of failure. Third, the EGU or EGUs in question would be subject to the requirements of a state plan that imposes emissions constraints such that the EGU or EGUs' operation in response to the reliability emergency resulted in levels of emissions that violated those constraints. We do not anticipate that EGUs operating under a plan that permitted emissions trading would meet these criteria.
The final guidelines provide a reliability safety valve for these types of situations. If an emergency situation arises, the state must submit an initial notification to the appropriate EPA regional office within 48 hours that it is necessary to modify the emission standards for a reliability-critical affected EGU or EGUs for up to an initial 90 days. The notification must include a full description, to the extent it is known at the time, of the emergency situation that is being addressed. It must also identify with particularity the affected EGU or EGUs that are required to run to assure reliability. It must also specify the modified emission standards at which the affected EGU or EGUs will operate. The EPA will consider this notification to be an approved short-term modification to the state plan, allowing the EGU to operate at an emission standard that is an alternative to the emission standard originally specified in the relevant state plan, subject to confirmation by the further documentation described below.
Within 7 days of submitting the initial notification, the state must submit a second notification providing documentation to the appropriate EPA regional office that includes a full description of the reliability concern and why an unforeseen, emergency situation that threatens reliability requires the affected EGU or EGUs to operate under modified emission standards (including discussion of why the flexibilities provided under the state's plan are insufficient to address the concern). The state must also describe in its documentation how it is coordinating or will coordinate with relevant reliability coordinators and planning authorities to alleviate the problem in an expedited manner, and indicate the maximum time that the state anticipates the affected EGU or EGUs will need to operate in a manner inconsistent with its or their obligations under the state's approved plan, and the modified emission standards or levels at which the affected EGU or EGUs will be operating at during this period if it has changed from the initial notification. The documentation must also include a written concurrence from the relevant reliability coordinator and/or planning authority confirming the existence of the imminent reliability threat and supporting the temporary modification request or an explanation of why this kind of concurrence cannot be provided. Additionally, if the relevant planning authority has conducted a system-wide or other analysis of the reliability concern, the state must include that information in its request. If the state fails to submit this documentation on a timely basis, the EPA will notify the state, which must then notify the affected EGU(s) that they must operate or resume operations under the original approved state plan emission standards.
It is important to note that the affected EGUs must continue to monitor and report their emissions and generation pursuant to requirements in this final rule and under the state plan during any short-term modification. For the duration of the up to 90-day short-term modification, the emissions of the affected EGU or EGUs that exceed their obligations under the approved state
During this short-term modification period, the EPA expects that the source, the state and the relevant reliability coordinator and/or planning authority will assess whether the reliability issue can be addressed in a way that would allow the EGU or EGUs to resume operating under the original approved state plan within the 90-day period or whether revisions to the state plan need to be made to address the unexpected circumstances for the longer term (the unexpected unavailability of a nuclear unit, for example).
The EPA recognizes that an emergency may persist past 90 days. At least 7 days before the end of the initial 90-day reliability safety valve period, the state must notify the appropriate EPA regional office whether the reliability concern has been addressed and that the EGU or EGUs can resume meeting the original emission standards established in the state plan prior to the short-term modification.
If there still is a serious, ongoing reliability issue at the end of the short-term modification period that necessitates the EGU or EGUs to emit beyond the amount allowed under the state plan, the state must provide to the EPA a notification that it will be submitting a state plan revision and submit the plan revision as expeditiously as possible, specifying in the notice the date by which the revision will be submitted. The state must document the ongoing emergency with a second written concurrence from the relevant reliability coordinator and/or planning authority confirming the continuing urgent need for the EGU or EGUs to operate beyond the requirements of the state plan and that there is no other reasonable way of addressing the ongoing reliability emergency but for the EGU or EGUs to operate under an alternative emission standard than originally approved under the state plan. In this event, the EPA will work with the state on a case-by-case basis to identify an emission standard for the affected EGU or EGUs for the period before a new state plan revision is approved. After the initial 90-day period, any excess emissions beyond what is authorized in the original approved state plan will count against the state's overall goal or emission performance rate for affected EGUs.
The EPA intends for this reliability safety valve to be used only in exceptional situations. In addition, this reliability safety valve applies only to this final rule and has no effect on CAA requirements to which the state or the affected EGUs are otherwise subject. As discussed earlier, we are providing states with the flexibility to design programs that allow affected EGUs to meet compliance obligations while responding to reliability needs, even in emergency situations. This flexibility means that a conflict between the requirements of the state plan and maintenance of reliability should be extremely rare. We recognize, however, that a state with an inflexible plan could be faced with more than one emergency and in this case the reliability safety valve may be used more than once. If the state finds that a second reliability emergency arises that conflicts with the state plan, the state must submit a revision to its state plan so that the state plan is flexible enough to assure that such conflicts do not recur and that the state is providing for the implementation of the standards of performance for affected EGUs as required by the CAA.
f.
The EPA, DOE, and FERC have agreed to coordinate efforts to help ensure continued reliable electricity generation and transmission during the implementation of the final rule. The three agencies have developed a coordination strategy that reflects their joint understanding of how they will work together to monitor final rule implementation, share information, and resolve any difficulties that may be encountered. This strategy is based on the successful working relationship that the three agencies established in their joint effort to work together to monitor reliability during MATS implementation.
g.
The EPA appreciates that a large number of entities from many different industry perspectives have published reports and analysis with respect to electric reliability and the 111(d) proposed rule. We take concerns about reliability very seriously, and we appreciate the attention given to this issue in the comments and shared with us in public forums. It is important to note that these studies were conducted prior to promulgation of this final rule, and thus were only able to consider electric reliability with respect to the proposal. The EPA has made changes and improvements to the proposal in response to comments and new information, and some of the changes are relevant to the final rule's potential effect on electric reliability. One notable change pertains to the start of the interim period, which is now 2022 rather than 2020. Another important change to the final rule is a more gradual phase-in of the BSER for affected EGUs over the interim period (from 2022 through 2029). The final rule also provides considerable flexibility and multiple pathways to states, including allowing their EGUs to use multi-state trading and other approaches, which would allow essential units to continue to meet their compliance obligation while generating even at unplanned but reliability-critical levels. In addition, we have included in the final rule a reliability safety valve provision that can be utilized in certain emergency situations. These changes, in addition to already existing industry mechanisms and planning requirements, will help to ensure that industry will be able to maintain electric reliability. The EPA is confident that the final rule will cut harmful electric power plant pollution while maintaining a reliable electric grid because the final rule provides industry with the time and flexibility needed to continue its current and ongoing planning and investing to modernize and upgrade the electric power system.
In June of 2015, M.J. Bradley & Associates issued a report that enumerated a set of useful guiding principles for studying and evaluating the reliability impacts of the final rule.
NERC published its analyses of the proposed rule in November 2014 and again in April 2015.
Multiple ISOs/RTOs also provided analyses of the proposed rule, including MISO, PJM, ERCOT, and SPP.
ERCOT also performed an analysis, modeling numerous scenarios.
PJM conducted its own analysis at the request of the Organization of PJM States (OPSI).
WECC also produced a study which is part of a longer-term, phased effort.
Analysis Group analyzed the proposed rule, finding that it provides states and affected EGUs with a wide range of options and operational discretion that can prevent reliability issues while also reducing carbon pollution and costs.
We appreciate the time that multiple entities took to analyze and consider the potential impacts of the proposed rule. As we issue the final rule and states draft plans to implement the rule, we look forward to further analysis by these and other groups. Such analysis can provide states with needed resources to help them design state plans that will augment the efforts of the industry to maintain electric reliability.
States in designing their state plans should consider the effects of their plans on employment and overall economic development to assure that the opportunities for economic growth and jobs that the plans offer are manifest. To the extent possible, states should try to assure that any communities that can be expected to experience job losses can also take advantage of the opportunities for job growth or otherwise transition to healthy, sustainable economic growth. The EPA's illustrative analysis indicates that there may be some additional job losses in sectors related to coal extraction and generation that are attributable to implementation of this rule. At the same time, the EPA's illustrative analysis indicates that there may be new jobs in the utility power sector associated with both improving the efficiency of fossil fuel-fired power plants, construction and operation of new natural gas-fired and RE production, and actions to increase demand-side EE. Consideration of these effects in the context of the particulars of the state plan can help states craft plans that, to the extent possible, meet multiple environmental, economic, and workforce development goals.
The Partnerships for Opportunity and Workforce and Economic Revitalization (POWER) Initiative is a new interagency effort led by the Economic Development Administration in the Department of Commerce. POWER was launched to respond to current trends in the power sector: “The United States is undergoing a rapid energy transformation, particularly in the power sector. This transformation is producing cleaner air and healthier communities, and spurring new jobs and industries. At the same time, it is impacting workers and communities who have relied on the coal industry as a source of good jobs and economic prosperity, particularly in Appalachia, where competition with other coal basins provides additional pressure.”
In addition to POWER, however, the EPA encourages states to use economic and labor market analysis to identify where they can deploy strategies to: (1) Provide a range of employment and training assistance to workers, and economic development assistance to communities affected by the rapid changes underway in the power sector and closely related industries, to diversify their economies, attract new sources of investment, and create new jobs; and (2) mobilize existing education and training resources, including those of community and technical colleges and registered apprenticeship programs, to ensure that both incumbent and new workers are trained for the skills necessary to meet employer demand for new workers in the utility, construction and related sectors, that such training includes career pathways for members of low-income communities and other vulnerable communities to attain employment in these sectors, and that such training results in validated skill certifications for workers.
Some stakeholders commented that, to ensure that emission reductions are realized, it is important that construction, operations and other skilled work undertaken pursuant to state plans is performed to specifications, and is effective, safe, and timely. A good way to ensure a highly proficient workforce is to require that workers have been certified by: (1) An apprenticeship program that is registered with the U.S. DOL, Office of Apprenticeship or a state apprenticeship program approved by the DOL; (2) a skill certification aligned with the U.S. DOE Better Building Workforce Guidelines and validated by a third party accrediting body recognized by DOE; or (3) other skill certification validated by a third party accrediting body.
Some commenters have raised concerns that the emission guidelines and requirements for 111(d) state plans violate principles of federalism embodied in the U.S. Constitution, particularly the Tenth Amendment. These commenters claim that states will be unconstitutionally “coerced” or “commandeered” into taking certain actions in order to avoid the prospect of either a federal 111(d) plan applying to sources in the state, or of losing federal funds.
We disagree on both fronts. First, the prospect of a federal plan applying to sources in a state does not “coerce” or
Second, states that decline to take certain actions under this rule will not face the prospect of sanctions, such as withdrawn federal highway funds. CAA section 111 does not contain sanctions provisions, and we are finalizing revisions to these emission guidelines making explicit that the EPA will not withhold federal funds from a state on account of that state's failure to submit or implement an approvable 111(d) state plan.
Some commenters pointed to section 110(m) as a possible source of the EPA's sanction authority.
The EPA never intended to even imply that we would contemplate using this authority to encourage state participation in this rule under section 111. To the contrary, we believe that imposition of a federal plan rather than sanctions is the appropriate path in the context of this program. Accordingly, regardless of whether the EPA could theoretically apply discretionary sanctions against states in the section 111(d) context, the final rule forbids the agency from exercising any such authority. We have included in this rule a provision that prohibits the agency from imposing sanctions in the event that a state fails to submit or implement a satisfactory plan under this rule. As states consider whether to take advantage of the opportunity to develop state plans, they can be assured that the EPA will not withdraw federal funding should they decline to participate.
States that are recipients of EPA financial assistance must comply with all federal nondiscrimination statutes that together prohibit discrimination on the bases of race, color, national origin (including limited-English proficiency), disability, sex and age. These laws include: Title VI of the Civil Rights Act of 1964; Section 504 of the Rehabilitation Act of 1973; Section 13 of the Federal Water Pollution Control Act Amendments of 1972; Title IX of the Education Act Amendments of 1972; and the Age Discrimination Act of 1975. Compliance with these nondiscrimination statutes is a recipient's separate and distinct obligation from compliance with environmental regulations. In other words, all recipients are required to ensure that all aspects of their state plans do not violate any of the federal nondiscrimination statutes, including Title VI.
The EPA's Office of Civil Rights (OCR) is responsible for carrying out compliance with these federal nondiscrimination statutes and does so through a variety of means including: Complaint investigation; agency-initiated compliance reviews; pre-grant award assurances and audits; and technical assistance and outreach activities. Anyone who believes that any of the federal nondiscrimination laws enforced by OCR have been violated by a recipient of EPA financial assistance may file an administrative complaint with the EPA's OCR.
As part of the stakeholder outreach and comment processes, the EPA asked states what the agency could do to facilitate state plan development and implementation. In addition, after the comment period closed, the EPA continued to consult with state organizations including the Association of Air Pollution Control Agencies (AAPCA), Environmental Council of the States (ECOS), National Association of Clean Air Agencies (NACAA), National Association of Regulatory Utility Commissioners (NARUC), National Association of State Energy Officials (NASEO) and the National Governors Association (NGA).
Some states indicated that they wanted the EPA to create resources to assist with state plan development, especially resources related to accounting for RE and demand-side EE in state plans. They requested clear methodologies for estimating emission reductions from RE and demand-side EE policies and programs so that these could be included as part of their compliance strategies. Stakeholders said that these tools and metrics should build upon the EPA's “Roadmap for Incorporating Energy Efficiency/Renewable Energy Policies and Programs into State and Tribal Implementation Plans,” as well as the State Energy Efficiency Action Network's “Energy Efficiency Program Impact Evaluation Guide.” In addition, stakeholders requested clear guidance on how to measure the impacts of RE and demand-side EE programs using established EM&V protocols.
The EPA also heard that states would like guidance on plan development to be released at the same time as this final rule. This guidance should include allowable programs and policies for compliance, examples of compliance pathways, clear information on multi-state plan development, and identification of tools.
As a result of this feedback, in consultation with U.S. DOE and other federal agencies, the EPA continued to refine its toolbox of decision support resources at:
The EPA notes that our inclusion of a measure in the toolbox does not mean that a state plan must include that measure. In fact, inclusion of measures provided at the Web site does not necessarily imply the approvability of an approach or method for use in a state plan. States will need to demonstrate that any measure included in a state plan meets all relevant criteria and adequately addresses elements of the plan components discussed in section VIII.D of this preamble.
This section describes a range of emission reduction actions that may be taken at affected EGUs that reduce CO
The discussion in this section applies for both rate-based and mass-based plans. Additional accounting considerations for mass-based plans are discussed in section VIII.J. Additional accounting considerations for rate-based plans, including how actions that substitute for generation from affected EGUs or avoid the need for generation from affected EGUs may be used in a state plan to adjust the CO
Many actions will reduce the reported CO
• heat rate improvements;
• fuel switching to a fossil fuel with lower carbon content (
• integrated RE;
• CHP, including retrofit of an affected EGU to a CHP configuration, or revising the useful energy outputs (electrical and thermal) at an affected EGU already operating in a CHP configuration.
Heat rate improvements, fuel switching, integrating RE and CHP would not require any additional accounting or monitoring and reporting, because under the emission guidelines affected EGUs are already required to monitor and report CO
Certain actions that may be taken at an affected EGU to reduce CO
a.
However, the EPA noted that CCS may be a viable CO
Some commenters noted that there are opportunities to reduce the cost of CCS implementation by selling the captured CO
After consideration of the variety of comments we received on this issue, we are confirming our proposal that CCS is not an element of the BSER, but it is an available compliance measure for a state plan. EGUs implementing CCS would need to follow reporting requirements established in the final CAA section 111(b) rule for new affected EGUs.
b.
The EPA received comments suggesting that carbon capture and utilization (CCU) technologies should also be allowed as a CO
Potential alternatives to storing CO
The Skyonics Skymine® project, which opened its demonstration project in October 2014, is an example of captured CO
However, consideration of how these emerging alternatives could be used to meet CO
Several commenters also suggested that algae-based CCU (
Unlike geologic sequestration, there are currently no uniform monitoring and reporting mechanisms to demonstrate that these alternative end uses of captured CO
In the meantime, state plans may allow affected EGUs to use qualifying CCU technologies to reduce CO
c.
The EPA received multiple comments supporting the use of biomass feedstocks as a means of reducing CO
(1)
The EPA recognizes that the use of some biomass-derived fuels can play a role in controlling increases of CO
In November 2014, the agency released a second draft of the technical report,
The SAB peer review panel agreed that the use of biomass feedstocks derived from the decomposition of biogenic waste in landfills, compost facilities or anaerobic digesters did not constitute a net contribution of biogenic CO
In addition, as detailed in the President's Climate Action Plan,
Many states have recognized the importance of forests and other lands for climate resilience and mitigation, and have developed a variety of sustainable forestry policies, RE incentives and standards, and GHG accounting procedures. Some states, for example Oregon and California, have programs that recognize the multiple benefits that forests provide, including biodiversity and ecosystem services protection as well as climate change mitigation through carbon storage. Oregon has several programs focused on best forest management practices and sustainability, including the Oregon Indicators of Sustainable Forests, that promote environmentally, economically and socially sustainable management of state forests. California's Forest Practice Regulations support sustained production of high-quality timber while considering ecological, economic and social values, and the state's Greenhouse Gas Reduction Fund provides resources for forestry projects to improve forest health, maintain carbon storage and avoid GHG emissions from pests, wildfires and conversion to non-forest uses.
Several states focus on sustainable bioenergy, as seen with the sustainability requirements for eligible biomass in the Massachusetts RPS, which, among other requirements, limits old growth forest harvests. Many states employ complementary programs that together work to address sustainable forestry practices. For example, Wisconsin uses a state forest sustainability framework that provides a common system to measure the sustainability of the state's public and private forests, in conjunction with a series of voluntary best management guideline manuals for sustainable woody biomass and agriculturally-derived biomass. In addition to state-specific programs, some states also actively participate in sustainable forest management or certification programs through third-party entities such as the Sustainable Forestry Initiative (SFI) and the Forest Stewardship Council (FSC). For example, in addition to other state sustainability programs, New York has certified more than 780,000 acres of state forestland to both SFI and FSC's sustainable forest management programs. SFI and FSC have certified more than 63 and 35 million acres of forestland across the U.S., respectively.
These examples demonstrate how states already use diverse strategies to promote sustainable forestry and agricultural management while realizing their unique economic, environmental and RE goals. As states evaluate options for meeting the emission guidelines, they may consider how sustainably-derived biomass and sustainable forestry and agriculture programs, such as the examples highlighted above, may help them control increases of CO
The EPA is engaging in a second round of targeted peer review on the revised Framework with the SAB in 2015.
(2)
The EPA anticipates that some states may consider the use of certain biomass-derived fuels used in electricity generation as a way to control increases of CO
State plan submissions must describe the types of biomass that are being proposed for use under the state plan and how those proposed feedstocks or feedstock categories should be considered as “qualified biomass” (
With regard to assessing qualified biomass proposed in state plans, the EPA generally acknowledges the CO
Given the importance of sustainable land management in achieving the carbon goals of the President's Climate Action Plan, sustainably-derived agricultural and forest biomass feedstocks may also be acceptable as qualified biomass in a state plan, if the state-supplied analysis of proposed qualified feedstocks or feedstock categories can adequately demonstrate that such feedstocks or feedstock categories appropriately control increases of CO
Regardless of what biomass feedstocks are proposed, state plans must specify how biogenic CO
State plan submittals must ensure that all biomass used meets the state plan requirements for qualified biomass and associated biogenic CO
The EPA will review the appropriateness and basis for proposed qualified biomass and biomass treatment determinations and related accounting, monitoring and reporting measures in the course of its review of a state plan. The EPA's determination that a state plan satisfactorily proves that proposed biomass fuels qualify would be based in part on whether the plan submittal demonstrates that proposed state measures for qualified biomass and related biogenic CO
(3)
Affected EGUs may use qualified biomass co-fired with fossil fuels at an affected EGU. As discussed above in this section, not all forms of biomass are expected to be approvable and states should propose biomass feedstocks and treatment of biogenic CO
An affected EGU using qualified biomass as a fuel must monitor and report both its overall CO
(4)
Affected EGUs could fully repower to use primarily qualified biomass. The characteristics of affected EGUs, as discussed in section IV.D, include the use of at least 10 percent fossil fuel for applicability of these emission guidelines. An EGU repowering with at least 90 percent biomass fuels instead of fossil fuels becomes a non-affected
This section discusses considerations and requirements for different types of mass-based state plans. This includes mass-based state plans using emission budget trading programs, and coordination among such programs where states retain individual mass CO
As discussed in section VIII.I, measures that occur at affected EGUs will result in CO
This section addresses the use of emission budget trading programs in a mass-based state plan, including provisions required for such programs and the design of such programs in the context of a state plan. This includes program design approaches that ensure achievement of a state mass-based CO
a.
For a mass-based emission trading program approach, the state plan would include as its federally enforceable emission standards requirements that specify the emission budget and related compliance requirements and mechanisms. These requirements would include: CO
Where a state plan establishes mass-based emission standards for affected EGUs only, the emission standards and the implementing and enforcing measures may be included in the state plan as the full set of requirements implementing the emission budget trading program. Where an emission budget trading program in a state plan addresses affected EGUs and other fossil fuel-fired EGUs or emission sources, pursuant to the approaches described in sections VIII.J.2.b-d below, the requirements that must be included in the state plan are the federally enforceable emission standards in the state plan that apply specifically to affected EGUs, and the requirements that specifically require affected EGUs to participate in and comply with the requirements of the emission budget trading program. This includes the requirement for an affected EGU to surrender emission allowances equal to reported CO
b.
In Section VII.D, the EPA specifies that potential emission leakage must be addressed in a state plan with mass-based emission standards. The EPA received comments suggesting various solutions to this concern, such as the inclusion of new sources under the rule and quantitative adjustments to mass CO
To address the potential for emission leakage to new sources under a mass-based plan approach, which could prevent a mass-based program from successfully achieving a mass-based CO
1. Regulate new non-affected fossil EGUs as a matter of state law in conjunction with emission standards for affected EGUs in a mass-based plan. If a state adopts an EPA-provided mass budget
2. Use allocation methods in the state plan that counteract incentives to shift generation from affected EGUs to unaffected fossil-fired sources. If a state adopts allowance set-aside provisions exactly as they are outlined in the finalized model rule, this option could be presumptively approvable.
3. Provide a demonstration in the state plan, supported by analysis, that emission leakage is unlikely to occur due to unique state characteristics or state plan design elements that address and mitigate the potential for emission leakage.
In the first option, states may choose to regulate new non-affected fossil fuel-fired EGUs, as a matter of state law, in conjunction with federally enforceable emission standards for affected EGUs under a mass-based plan. This regulation of both new and existing sources, as part of a state plan approach, is conceptually analogous to a method that has been adopted by the mass-based systems adopted by California and the RGGI participating states. To address potential emission leakage under this option, the mass-based plan includes federally enforceable emission standards for affected EGUs, and the supporting documentation for the plan describes state-enforceable regulations for, at a minimum, all new grid-connected fossil fuel-fired EGUs that meet the applicability standards for EGUs subject to CAA section 111(b). States have the option of regulating a wider array of sources if they choose, as a matter of state law.
For this option, a state must adopt, as a matter of state law, a mass CO
EPA-specified mass CO
States can, in the alternative, provide their own projections for a new source CO
The second demonstration option allows states to use allowance allocation methods that counteract incentives to shift generation from affected EGUs to unaffected fossil-fired sources. These allocation approaches must be specified in state plans as part of the provisions for state allocation of allowances required under a mass-based plan approach (see section VIII.J.2.a). The EPA is proposing the inclusion of two allocation strategies as part of the mass-based approach in the proposed federal plan and model rule: Updating output-based allocations and an allowance set-aside that targets RE. These options are described in more detail below. If a state were to adopt allowance set-aside provisions exactly as they are outlined in the finalized model rule, they could be considered presumptively approvable. The allowance allocation alternative for addressing leakage was chosen for the federal plan and model rule proposal because EPA does not have authority to extend regulation of and federal enforceability to new fossil fuel-fired sources under CAA section 111(d), and therefore we cannot include them under a federal mass-based plan approach.
An updating output-based allocation method allocates a portion of the total CO
This allocation method can be implemented through the creation of a
The other allocation strategy included as part of the mass-based approach in the proposed federal plan and model rule is a set-aside of allowances to be allocated to providers of incremental RE. A set-aside can also be allocated to providers of demand-side EE, or to both RE and demand-side EE. The increased availability of RE generation can serve as another source of generation to satisfy electricity demand. Increased demand-side EE will reduce the demand that sources need to meet. Therefore, both RE and demand-side EE can serve to reduce the incentive that new sources have to generate, and therefore align their incentives with affected EGUs. Thus, increased RE and demand-side EE, supported by a dedicated set-aside, can also serve to address potential emission leakage.
If a state is submitting a plan with an allocations approach that differs from that of the finalized model rule, the state should also provide a demonstration of how the specified allocation method will provide sufficient incentive to counteract potential emission leakage.
Finally, a state can provide a demonstration that emission leakage is unlikely to occur, without implementing either of the two strategies above, as a result of unique factors, such as the presence of existing state policies addressing emission leakage or unique characteristics of the state and its power sector that will mitigate the potential for emission leakage. This demonstration must be supported by credible analysis. The EPA will determine if the state has provided a sufficient demonstration that potential emission leakage has already been adequately addressed, or if additional action is required as part of the state plan.
Aside from the possible incentives for emission leakage addressed in this section, there may be other potential generation incentives across states and unit subcategories that could increase CO
However, without a better understanding of the different mechanisms that states may ultimately choose to meet the emission guidelines, and how different requirements in different states may interact, the EPA cannot project every potential differential incentive that could lead to a loss of CO
c.
A mass-based emission budget trading program can be designed such that compliance by affected EGUs will achieve the state mass-based CO
Under this approach, compliance by affected EGUs with the mass-based emission standards in a plan would ensure that the state achieves its mass-based CO
For this type of plan, where the emission budget is equal to or less than the state mass CO
Banking provisions have been used extensively in rate-based environmental programs and mass-based emission budget trading programs. This is because banking reduces the cost of attaining the requirements of the regulation. The EPA has determined that the same rationale and outcomes apply under a CO
Banking also provides long-term economic signals to affected emission sources and other market participants where actions taken today will have economic value in helping meet tighter emission constraints in the future, provided those emission sources expect that the banked ERCs or emission allowances may be used for compliance in the future. Linking short-term and long-term economic incentives, which allows owners or operators of affected EGUs and other market participants to assess both short-term and long-term incentives when making decisions about compliance approaches or emission reduction investments, reduces long-term compliance costs for affected EGUs and ratepayer impacts. In addition, the increased temporal flexibility provided by banking would further help address potential electric reliability concerns, as banked ERCs can be used to meet emission standard requirements for an affected EGU.
d.
As described in section VIII.C above, under the emission standards plan type, a mass-based emission budget trading program with broader source coverage and other flexibility features may be designed such that compliance by affected EGUs (or compliance by affected EGUs plus new fossil fuel-fired EGUs meeting applicable requirements under state law) would assure achievement of the applicable state mass-based CO
However, emission budget trading programs, including those currently implemented by California and the RGGI participating states, include a number of different design elements that functionally expand the emission budget under certain circumstances. If a state chose, it could apply such mass-based emission standards, in the form of an emission budget trading program that differs in design from that outlined in section VIII.J.2.c above. These types of emission budget trading programs must be submitted as a part of a state measures plan type. Where an emission budget trading program addresses affected EGUs and other fossil fuel-fired EGUs, the requirements that must be included in the state plan are the federally enforceable emission standards in the state plan that apply specifically to affected EGUs, and the requirements that specifically require affected EGUs to participate in and comply with the requirements of the emission budget trading program. This includes the requirement for an affected EGU to surrender emission allowances equal to reported CO
Such state programs could include a number of different design elements. This includes broader program scope, where a program includes other emission sources beyond affected EGUs subject to CAA section 111(d) and new fossil fuel-fired EGUs, such as industrial sources. Programs might also include design elements that make allowances available in addition to the established emission budget. This includes project-based offset allowances or credits from GHG emission reduction projects outside the covered sector and cost containment reserve provisions that make additional allowances available at specified allowance prices.
In the case where an emission budget trading program contains elements that functionally expand the emission budget in certain circumstances, compliance by affected EGUs with the mass-based emission standards would not necessarily ensure that CO
Where a state chooses to retain such flexibility mechanisms as part of an emission budget trading program, the program may only be implemented as part of a state measures plan type because these state flexibility mechanisms would not assure CO
Under this type of approach, the state would be required to include a demonstration,
e.
The EPA notes that while an emission budget trading program included in an emission standards plan must be designed to achieve a state mass-based CO
(1)
(2)
3. Multi-state coordination: Mass-based emission trading programs.
An individual state may provide for the use of CO
Two different implementation approaches could be used to create such links. A state could submit a “ready-for-interstate-trading” plan using an EPA-approved tracking system, but the plan would not identify links with other states. A state could also submit a plan with specified bilateral or multilateral links that explicitly identify partner states.
Interstate allowance linkages would not affect the approvability of each state's individual plan. However, different considerations apply for the approvability of an individual plan with such links, based on whether the emission budget trading program in the plan applies only to affected EGUs or includes other emission sources, and if the plan is designed to meet a state mass-based CO
Under the first “ready-for-interstate-trading” implementation approach, a state would indicate in its state plan that its emission budget trading program will be administered using an EPA-approved (or EPA-administered) emission and allowance tracking system.
A state would indicate in its plan submittal that its emission budget trading system will use a specified EPA-approved tracking system. The state would also indicate in the regulatory provisions for its emission budget trading program that it would recognize as usable for compliance any emission allowance issued by any other state with an EPA-approved state plan that also uses the specified EPA-approved tracking system.
States could also adopt such a collaborative emission trading approach over time (through appropriate state plan revisions if the plan is not already structured as ready-for-interstate-trading), without requiring all of the original participating states to revise their EPA-approved plans.
Under the second implementation approach, a state could specify the other states from which it would recognize issued emission allowances as usable for compliance with its emission budget trading program. The state would indicate in the regulatory provisions for its emission budget trading program that emission allowances issued in other identified partner states may be used by affected EGUs for compliance. Such plans must indicate how allowances will be tracked from issuance through use for compliance, through either a joint tracking system, interoperable tracking systems, or EPA-administered tracking system. The EPA would assess the design and functionality of this tracking system(s) when reviewing individual submitted state plans.
Under this approach, states could also join such a collaborative emission trading approach over time. However, all participating states would need to revise their EPA-approved plans. If the expanded linkage is among previously approved plans with mass-based emission standards, approval of the plan revision would be limited to assessing the functionality of the shared tracking system or interoperable tracking systems
a.
For individually submitted plans, interstate emission allowance linkages would not affect the approvability of each state's plan. However, approvability of an individual linked plan would differ based on the structure of the emission budget trading program included in the plan. These differences for plan approvability address distinctions among programs that include only affected EGUs and programs that cover a broader set of emission sources, as well as if the plan is designed to meet a state mass-based CO
(1)
Under this approach, if the emission budget for the mass-based emission standard in each plan is equal to or lower than the state's mass-based CO
The same accounting approach will apply for such plans in all cases, even if the state is linked to another state emission budget trading program that includes a broader set of emission sources (
(2)
Generally, such plans must demonstrate that the mass-based CO
During plan implementation, the EPA would assess whether the affected EGUs in a state achieved the state's mass-based CO
•
•
Where CO
A net transfer of CO
This section discusses considerations and requirements for rate-based state plans. This section discusses eligibility, accounting, and quantification and verification requirements (EM&V) for the use of CO
Section VIII.K.1.a below describes the basic accounting method for adjusting a CO
a.
A CO
As discussed in this section, a wide range of actions may be taken to adjust the reported CO
The EPA believes that the broad categories of measures listed in this section address the wide range of actions that are available to reduce CO
This section discusses the basic accounting method for adjusting the reported CO
(1)
In this final rule, the reported CO
The measures described in these sections reduce mass CO
The following provides a simple calculation example of how MWh of replacement generation added to the denominator of an affected EGU's reported CO
In the case of rate-based CO
Numerous commenters requested that the EPA ensure consistency between goal-setting calculations and the methodology used to demonstrate achievement of a CO
When demonstrating achievement of a CO
Several commenters suggested that the EPA consider the regional nature of the electricity grid and how RE and demand-side EE impacts generation and CO
Because of the separate accounting of MWhs and CO
The MWh accounting method also creates a crediting system or rate adjustment process that is indifferent to the rate-based CO
(2)
The EPA is finalizing certain general eligibility requirements for resources used to adjust a CO
As discussed in the sections that follow, the general eligibility criteria address:
• The date from which eligible measures may be installed (
• the date from which MWh from eligible measures may be counted, and applied toward adjusting a CO
• the need to demonstrate that eligible measures replace or avoid generation from affected EGUs.
(a)
Incremental emission reduction measures, such as RE and demand-side EE, can be recognized as part of state plans, but only for the emission reductions they provide during a plan performance period. Specifically, this means that measures installed in any year after 2012 are considered eligible measures under this final rule, but only the quantified and verified MWh of electricity generation or electricity savings that they produce in 2022 and future years may be applied toward adjusting a CO
As discussed in section VIII.C.2.a, a MWh of generation or savings that occurs in 2022 or a subsequent year may be carried forward (or “banked”) and applied in a future year. For example, a MWh of RE generation that occurs in 2022 may be applied to adjust a CO
This eligibility date criterion is consistent with the date of installation for “incremental” RE capacity that is included in the BSER building block 3, which is the basis for RE MWh incorporated in the CO
Many commenters asserted that proposed state goals did not sufficiently account for actions states take that reduce CO
Commenters' concerns about treatment of early actions are further addressed by changes from proposal to the BSER assumptions and the methodology used by the EPA to establish the CO
First, affected EGUs that have maximized their CO
Second, generation from existing RE capacity installed prior to 2013 has been excluded from the EPA's calculation of the CO
Third, commenters expressed concern that demand-side EE targets as part of proposed state goals reflected an assumption of installation of increased EE measures starting in 2017, which seemed to be an implicit requirement to take action prior to the performance period. Because demand-side EE is not used in calculating the CO
(b)
Eligible measures must be grid-connected. This eligibility criterion aligns incremental NGCC generation in building block 2. It also aligns with RE generation in building block 3 of the BSER, which substitutes for the need for generation from affected EGUs.
All EE measures must result in electricity savings at a building, facility, or other end-use location that is connected to the electricity grid. EE measures only avoid electric generation from grid-connected EGUs if the electrical loads where the efficiency improvements are made are interconnected to the grid.
Commenters sought clarity on this issue, so the EPA is providing this requirement as part of the final rule. Some commenters advocated for the inclusion of measures that were not grid connected as eligible resources, arguing that some of these measures substituted for non-affected EGUs and resulted in reductions in CO
(c)
All eligible emission reduction measures, including RE generation and demand-side EE, may occur in any state, with certain limitations, as described below. To the extent these measures are tied to a state plan,
State plans must demonstrate that emission standards and state measures (if applicable) are non-duplicative. Given the geographic eligibility approach described here, this includes a demonstration that a state plan does not allow recognition of a MWh, for use in adjusting the CO
The EPA received many comments on the treatment of in-state and out-of-state RE and demand-side EE. Most commenters recommended crediting of both in-state and out-of-state RE and demand-side EE measures, similar to the final rule approach for eligible emission reductions measures. Commenters argued that this approach makes sense based on the nature of the interconnected electricity grid and allows states and utilities to fully account for their RE and demand-side EE efforts, whether that RE or EE, and its related impacts, occurs inside or outside of their state. Some commenters expressed concerns that, at proposal, states with significant RE resources had large amounts of existing RE capacity included in their state CO
(i)
As discussed above, eligible measures for adjusting the CO
These criteria are intended to address the fact that eligible measures should lead to substitution of generation from affected EGUs, with related impacts on CO
For RE measures located in a mass-based state to have some or all of its generation counted under a rate-based plan in another state, it must be demonstrated that the generation was delivered to the grid to meet electricity load in a state with a rate-based plan.
Under an emission standards plan, this demonstration must be made by the provider of the RE measure seeking ERC issuance under the rate-based emission standards in a rate-based state, as part of the eligibility application for the measure.
Further examples of eligible demonstrations and how they should be outlined in state plans are provided in section VIII.L.
(ii)
States, including areas of Indian country, that do not have any affected EGUs within their borders may be providers of credits for generation from zero- or low-emitting resources to adjust CO
For participating states, they must adhere to EM&V standards, installation dates, and any other criteria that apply to all states. Section VIII.K.3 below identifies and discusses the EM&V requirements used to quantify MWh savings from generation from zero- or low-emitting sources.
States, including areas of Indian country, that do not have any affected EGUs may provide ERCs to adjust CO
In addition to generation from zero- or low-emitting resources, demand-side EE resources in areas of Indian country located within the borders of states with rate-based emission standards for affected EGUs may also be issued ERCs. In these instances, the area of Indian country is located within the rate-based service area subject to a rate-based state plan. The ERCs from demand-side EE resources must meet the eligibility requirements to adjust a CO
Non-contiguous states and territories may not be providers of ERCs to the contiguous U.S. states. As discussed previously in section VII.F, we have not set CO
(iii)
The EPA will work with states using the rate-based approach that are interested in allowing the use of RE from outside the U.S. to adjust CO
The EPA received comments encouraging the use of international zero-emitting electricity imports in state plans, particularly hydroelectric power from Canada. Canada currently provides states such as Minnesota and Wisconsin with RE through existing grid connections. New projects are in various stages of development to increase generating capacity, which could be called upon as a base load resource to supplement variable forms of RE generation. Commenters said that the EPA should permit the use of all incremental hydropower—both domestic and international—towards EGU CO
(3)
RE measures may be used to adjust a CO
Quantification and accounting criteria for incremental RE (and nuclear generation) are as follows. The incremental generating capacity (in nameplate MW) is divided by the total uprated generating capacity (in nameplate MW) and then multiplied by generation output (in MWh) from the uprated generator. For example, if a hydroelectric power plant expands generating nameplate capacity from 100 MW to 125 MW and generation output increased to 1,000 MWh, then 200 MWh ((25 MW/125 MW) * 1,000 MWh) is eligible for use in adjusting a CO
Many commenters supported using RE deployment as measures to adjust the CO
Certain additional requirements apply for hydropower and biomass (including waste-to-energy) RE, as described below.
(a)
Consistent with other types of RE, new hydroelectric power generating capacity installed after 2012 is eligible for use in adjusting a CO
Relicensed facilities are considered existing capacity and, therefore, are not eligible for use in adjusting a CO
The EPA noted that many commenters preferred that generation from hydropower displace generation from fossil sources. One commenter suggested that existing zero-emitting sources, including hydropower, do not reduce emissions from existing fossil generation, but that new or uprated zero-emitting sources would, because of their low variable rate, reduce fossil emissions. Several commenters recommended allowing incremental generation from new or uprated zero-emitting sources, including hydropower, be available for compliance.
(b)
RE generating capacity installed after 2012 that uses qualified biomass as a fuel source is eligible for use in adjusting a CO
Section VIII.K describes the requirements and procedures for EM&V, and discusses how all eligible resources must demonstrate how they will quantify and verify MWh savings using best-practice EM&V approaches. One way to make this demonstration for eligible resources could be to use the presumptively approvable EM&V approaches that are included in the final model trading rule.
(c)
Qualified biomass may include the biogenic portion of MSW combusted in a waste-to-energy facility.
MSW can be directly combusted in waste-to-energy facilities to generate electricity as an alternative to landfill disposal. In the U.S., almost all incineration of MSW occurs at waste-to-energy facilities or industrial facilities where the waste is combusted and energy is recovered.
Information in the revised
When developing their plans, states planning to use waste-to-energy as an option for the adjustment of a CO
A state plan must include a method for determining the proportion of total MWh generation from a waste-to-energy facility that is eligible for use in adjusting a CO
The EPA received multiple comments supporting the use of waste-to-energy as part of state plans. Some commenters expressed concern that non-biogenic materials, such as plastics and metal, would be incinerated along with biogenic materials. As discussed above, only electric generation related to the biogenic fraction of MSW at a waste-to-energy facility added after 2012 is eligible for use in adjusting a CO
(4)
Avoided MWh that result from DSM may be used to adjust a CO
(5)
Energy storage may not be directly recognized as an eligible measure that can be used to adjust a CO
The EPA received multiple comments regarding the overall merits of energy storage. Consistent with the discussion above, the majority of commenters observed that storage technology enables greater grid penetration of RE and supports more efficient and effective operations of both RE and fossil-fuel plants. Commenters further noted that energy storage can provide RE to the grid when it is most needed, while simultaneously taking pressure off fossil-fuel plants to respond to sudden shifts in demand. Despite broad acknowledgment of the benefits of storage, public comments underscore its indirect and supporting role in providing zero-emission MWh to the grid (consistent with the EPA's decision to exclude energy storage as an eligible measure that can be used to adjust a CO
(6)
Electricity T&D measures that improve the efficiency of the T&D system and/or reduce electricity use may be used to adjust a CO
To be eligible, T&D measures must be installed after 2012. This general eligibility requirement is discussed above in section VIII.K.1.a. The MWh of avoided losses or reduction in end-use that result from T&D measures must be appropriately quantified and verified, as discussed in section VIII.K.3.
(7)
Demand-side EE measures may be used to adjust a CO
Numerous commenters expressed support for including demand-side EE as an eligible measure states and affected EGUs can use to meet the emission guidelines. Commenters touted the value of demand-side EE as a resource that delivers energy savings, lowers bills, creates jobs and reduces CO
(8)
As is discussed in section V.A.3, upon consideration of comments received, the EPA has not included nuclear generation from either existing or under construction units in the determination of the BSER. In addition to comments received on the provisions for determining the BSER, the EPA also received comments requesting that the EPA allow all generation from nuclear generating units to be recognized as an
The EPA has determined that generation from new nuclear units and capacity uprates at existing nuclear units will be eligible for use in adjusting a CO
In contrast, any incremental zero-emitting generation from new nuclear capacity would be expected to replace generation from affected EGUs and, thereby, reduce CO
Applicable generation (in MWh) from incremental nuclear power is determined in the same manner as that described for incremental RE above.
(9)
Electric generation from non-affected CHP units
Where a state plan provides for the use of electrical generation from eligible non-affected CHP units to adjust the reported CO
The proposed accounting method in a state plan must address the following considerations. The accounting approach proposed in a state plan must take into account the fact that a non-affected CHP unit is a fossil fuel-fired emission source, as well as the fact that the incremental CO
This low CO
Non-affected CHP units can use qualified biomass fuels. As described in section VIII.I.2.c, states must submit state plan requirements regarding qualified biomass feedstocks and treatment of biogenic CO
Most comments received on CHP recommended that the EPA explicitly describe how CHP can be accounted for in a state plan. Commenters described the CO
(10)
WHP units that meet the eligibility criteria under section VIII.K.1 may be used to adjust the CO
b.
This section addresses measures that may not be used to adjust a CO
The EPA received comments both supporting and opposing the use of new NGCC units in state plans. In addition to leakage concerns, commenters expressed concern with the potential incentives created by including new NGCC capacity in the BSER or as a compliance mechanism in state plans. Some commenters suggested that including new NGCC capacity in the BSER or for compliance would distort market incentives to build new NGCC units, particularly if new units were allowed to generate ERCs that could be sold to affected EGUs. These commenters suggested that the additional incentive for new NGCC units could make existing NGCC units less competitive. Other commenters suggested that including new NGCC capacity in state plans would promote generation from new CO
In addition, other new and existing non-affected fossil fuel-fired EGUs that are not subject to CAA section 111(b) or 111(d), such as simple cycle combustion turbines, may not be used to adjust the CO
c.
Measures that reduce CO
As made clear in the proposal,
The EPA also specifically proposed that for state plans that rely on measures that avoid EGU CO
The EPA will review a state plan submittal including a rate-based emission trading program to assure that the plan contains the requirements necessary to assure the integrity of a rate-based approach, and therefore provide for the implementation and enforcement of rate-based emission standards. These requirements are discussed in more detail in this section.
The EPA also notes it is proposing model rules for both mass-based and rate-based emission trading programs. State plans that include the finalized model rule for a rate-based emission trading program could be presumptively approvable as meeting the requirements of CAA section 111(d) and these emission guidelines. The EPA would evaluate the approvability of such plans through independent notice and comment rulemaking.
A state may issue ERCs to an affected EGU that performs at a CO
ERCs may be used by an affected EGU to adjust its reported CO
a.
ERCs may be issued to affected EGUs that emit below a specified CO
Following determination of the number of ERCs an affected EGU is eligible to receive, based on an affected EGU's reported CO
The accounting method that may be applied in a state plan differs depending on whether a state plan includes a single rate-based emission standard that applies to all affected EGUs (
Where a state plan includes emission standards in the form of a single rate-based emission standard that applies to all affected EGUs, the reference rate is the CO
ERCs
For the example above, the calculation is as follows:
ERCs = MWh reported × (2,000−1,000)/2,000 = MWh reported × 0.5
If the affected EGU in this example generated 1,000,000 MWh, 500,000 ERCs would be issued.
Where a state plan includes separate emission standards for subcategories of affected EGUs, specifically affected fossil fuel-fired electric utility steam generating units and stationary combustion turbines, the reference rate differs for affected fossil fuel-fired electric utility steam generating units and stationary combustion turbines. Additionally, if the state plan applies emission standards for its affected EGUs that are equal to the subcategorized CO
For affected steam generating units, the reference CO
ERCs
For an affected NGCC stationary combustion turbine in a subcategorized rate-based emission trading program, the following equation provides a required accounting method for generating ERCs based on operation with respect to the NGCC unit's emission standard:
ERCs = NGCC unit's reported MWh—((NGCC unit's CO
According to this equation, ERC issuance is assessed based on the difference between the CO
In a subcategorized rate-based emission trading program, a state must use the incremental operation of an affected NGCC unit quantified for building block 2 to allow a NGCC unit to generate ERCs based on its expected incremental generation.
A state plan that provides for the use of ERCs issued based on incremental affected NGCC generation must provide a required calculation method that allows for issuance of ERCs based on the ability of incremental generation from affected stationary combustion turbines to substitute for generation from affected steam generating units (as represented in building block 2), while also respecting the fact that affected stationary combustion turbines must also meet an assigned CO
The EPA will review whether a state's accounting method is approvable per the requirements of the statute and this final rule as part of its overall plan review of the rate-based emission standards and implementing and enforcing measures in the state plan. The EPA notes that the proposed model rule for a rate-based emission trading program includes a proposed accounting method and takes comments on alternatives. The accounting method provided in a final model rule could be a presumptively approvable approach for issuance of ERCs based on the ability of incremental generation from affected stationary combustion turbines to
b.
ERCs may be issued for qualifying measures.
The EPA has determined that state requirements for an eligibility application must include review of the application by an independent verifier, approved by the state as eligible per the requirements of the final emission guidelines to provide such verification, prior to submittal. This requirement builds on the approach used for assessing GHG offset projects, both in international emission trading programs and the GHG emission budget trading programs implemented by California and the RGGI participating states.
The EPA has determined that independent verification requirements are necessary to ensure the integrity of state rate-based emission trading programs included in a state plan, given the wide range of eligible measures that may generate ERCs and the broad geographic locations in which those measures may occur. Inclusion of an independent verification component provides technical support for state regulatory bodies to ensure that eligibility applications and M&V reports are thoroughly reviewed prior to issuance of ERCs. Inclusion of an independent verification component is also consistent with similar approaches required by state PUCs for the review of demand-side EE program results and GHG offset provisions included in state GHG emission budget trading programs.
State plans with rate-based emission trading programs must include requirements regarding the qualification status of an independent verifier. An independent verifier is a person (including any company, any corporate parent or subsidiary, any contractors or subcontractors, and the actual person) who has the appropriate technical and other qualifications to provide verification reports. The independent verifier must not have, or have had, any direct or indirect financial or other interest in the subject of its verification report or ERCs that could impact its impartiality in performing verification services. State plans must require that a person be approved by the state as an independent verifier, as defined by this final rule, as eligible to perform the verifications required under the approved state plan. State plans must also include a mechanism to temporarily or permanently revoke the qualification status of an independent verifier, such that it can no longer provide verification services related to an eligibility application or M&V report for at least the duration of the period it does not meet the qualification requirements for independent verifiers in an approved state plan. The EPA's proposed model rate-based emission trading rule contains provisions addressing accreditation and conflicts of interest for independent verifiers. State plans that adopt the finalized model rule could be presumptively approvable with respect to these requirements regarding independent verifiers.
The state's eligibility requirements and application procedures must ensure that only eligible actions may generate ERCs and that documentation is submitted only once for each program or project, and to only one state program.
In the second step of the process, following implementation of the RE/EE program or project (as described in this example) that was approved in step one, the RE/EE provider periodically submits a M&V report to the state regulatory body documenting the results of the
State plan requirements must ensure that only one ERC is issued for each verified MWh. This is addressed through registration in the tracking system of programs and projects that have been qualified for the issuance of ERCs, to ensure that documentation is submitted only once for each RE/EE action, and to only one state program.
c.
State requirements must include provisions to ensure that ERCs issued to any eligible entity are properly tracked from issuance to submission by affected EGUs for compliance (where ERCs are “surrendered” by the owner or operator of an affected EGU and “retired” or “cancelled”), to ensure they are only used once to meet a regulatory obligation. This is addressed through specified requirements for tracking system account holders, ERC issuance, ERC transfers among accounts, compliance true-up for affected EGUs,
The EPA received a number of comments from states and stakeholders about the value of the EPA's support in developing and/or administering tracking systems to support state administration of rate-based emission trading systems. This could include regional systems and/or a national system. The EPA is exploring options for providing such support and is conducting an initial scoping assessment of tracking system support needs and functionality.
d.
Because the goal of this rulemaking is the actual reduction of CO
An approvable state plan that allows affected EGUs to comply with their emission standards in part through reliance on ERCs must include provisions making clear that an affected EGU may only demonstrate compliance with an ERC that represents the one MWh of actual energy generation or savings that it purports to represent and otherwise meets the emission guidelines.
e.
ERCs issued in 2022 or a subsequent year may be carried forward (or “banked”) and used for demonstrating compliance in a future year.
f.
The EPA notes that state-administered and state-overseen EE programs, such as those administered by state-regulated electric distribution utilities, could play a key role in supplying energy savings to a rate-based emission trading system in the form of ERCs. These programs have been the primary means for delivering EE programs and energy savings at scale, and also allow for a state to conduct a portfolio planning process to guide EE program design and focus in a manner that best provides multiple benefits to electricity ratepayers in a state. Such portfolio planning processes typically treat EE as an energy resource comparable to electricity generation.
The EPA also notes that non-ERC certificates may be issued by states and other bodies for MWh of energy generation and energy savings that are used to meet other state regulatory requirements, such as state RPS and EERS, or by individuals to make environmental or other claims in voluntary markets.
The EPA defines an ERC in the emission guidelines as a tradable compliance instrument that represents a zero-emission MWh (for the purposes of meeting the emission guidelines) from a qualifying measure that may be used to adjust the reported CO
An ERC is issued separately from any other instruments that may be issued for a MWh of energy generation or energy savings from a qualifying measure. Such other instruments may be issued for use in meeting other regulatory requirements (
The EPA notes that the definitions of other instruments, such as RECs, differ (as established under state statute, regulations, and PUC orders) and that requirements under state regulatory programs that use such instruments, such as state RPS, also differ. As a result, states may want to assess, when developing their state plan, how such existing instruments may interact with ERCs. For example, a state may want to assess how issuance of ERCs pursuant to a state plan may interact with compliance with a state RPS by entities affected under relevant state RPS regulations or PUC orders. The interaction of other instruments and ERCs may also impact existing or future arrangements in the private marketplace. Actions taken by states, separate from the design of their state plan, could address a number of these potential interactions. For example, state RPS regulations that specify a REC for a MWh of RE generation, and the attributes related to that MWh, may or may not explicitly or implicitly recognize that the holder of the REC is also entitled to the issuance of an ERC for a MWh of electricity generation from the eligible RE resource. This could impact existing and future RE power purchase agreements or REC purchase agreements. Such interactions among existing instruments and ERCs could also impact how marketing claims are made in the voluntary RE market. How a state might choose to address these potential interactions will depend on a number of factors, including the utility regulatory structure in the state, existing statutory and regulatory requirements for state RPS, and existing RE power purchase agreements and REC contracts.
g.
The EPA is requiring that states periodically review the administration of their rate-based emission trading programs. The results of these program reviews must be submitted by states to the EPA as part of their required reports on the implementation of their state plans, as described in sections VIII.D.a.(5) and VIII.D.2.b.(4), and must be made publicly available. Such a review submitted as part of a required state report provides for the implementation of rate-based emission standards per the requirements of CAA section 111(d)(2). For a rate-based emission trading program, the review must cover the reporting period addressed in the state's periodic reports to the EPA on plan implementation.
The program review must address all aspects of the administration of a state's rate-based emission trading program, including the state's evaluations and regulatory decisions regarding eligibility applications for ERC resources and M&V reports (and associated EM&V activities), and the state's issuance of ERCs. The program review must assess whether the program is being administered properly in accordance with the state's approved plan; whether ERC eligibility applications and M&V reports are being properly evaluated and acted upon (
States must collect, compile, and maintain sufficient data in an appropriate format to support the periodic program review. The EPA will review the results of each program review. The EPA may also audit a state's administration of its rate-based emission trading program and pursue appropriate remedies where significant deficiencies are identified.
This section discusses EM&V for RE, demand-side EE, and other measures that are used to generate ERCs or otherwise adjust an emission rate.
As discussed in section VIII.K.1, quantified and verified MWh of RE generation, EE savings,
a.
The EPA proposed that a state plan that incorporates RE and demand-side
The proposal and associated “State Plans Considerations” TSD
As a result, the agency took comment on whether this infrastructure is appropriate in the context of approvable state plans for use in rate-based state plans that include RE, demand-side EE, and other measures. The majority of commenters addressing this question responded affirmatively, indicating that existing EM&V infrastructure is appropriate to assure quality, credibility, and integrity. However, commenters also noted that EM&V methods are routinely improving and changing over time, and that the EPA's requirements and guidance should be responsive to such changes, should avoid locking in outdated methods, and should be updated to maintain relevance.
Another point made by commenters is that, despite the observed improvements in EM&V over time, quantification knowledge is more robust for some EE program and policy types than for others. Additionally, there is relatively limited experience applying EM&V protocols and procedures to emission trading programs, where each MWh of replaced generation can be bought and sold by a regulated source. As a result, the EPA's final emission guidelines and proposed model rule include a number of safeguards and quality-control features that are intended to ensure the accuracy and reliability of quantified EE savings.
b.
As discussed in section VIII.K.2, these final guidelines require that state plans include a requirement that EM&V plans and M&V reports be submitted to the state for rate-based emission trading programs. States must require that at the initiation of an eligible measure, project providers must develop and submit to the state an EM&V plan that documents how requirements for quantification and verification will be carried out over the period that MWh generation or savings are produced. States must also require that after a project or program is implemented, the provider must submit periodic M&V reports to confirm and describe how each of the requirements was applied. These reports must also specify the actual MWh savings or generation results, as quantified by applying EM&V methods on a retrospective (ex-post) basis. States may not allow MWh values that are quantified using ex-ante (pre-implementation) estimates of savings. As previously described, the EPA took comment on the suitability of current state and utility EM&V approaches for RE and demand-side EE programs in the context of an approvable state plan. These final requirements regarding EM&V plans and M&V reports are intended to leverage and closely resemble those already in routine use.
For energy generating resources, including RE resources, states may leverage the programs and infrastructure they have in place for achievement of their RPS and take advantage of registries in place for the issuance and tracking of RECs. Many existing REC tracking systems already include well-established safeguards, documentation requirements, and procedures for registry operations that could be adapted to serve similar functions in relation to the final emission guidelines. For example, a key element of RPS compliance in many states that parallels the final rule's requirements is that each generating unit must be uniquely identified and recorded in a specified registry to avoid the double counting of credits at the time of issuance and retirement. In addition, the existing reports and documentation from tracking systems may, together with eligible independent third party verification reports, serve as the substantive basis for eligibility applications, EM&V plans and M&V reports for the issuance of ERCs to energy generating resources for affected EGUs to meet their obligations under the final rule. With respect to actual monitoring requirements, many existing REC registries include provisions for the monitoring of MWh of generation that would be appropriate to meet state plan requirements pursuant to the final rule, such as requirements to use a revenue quality meter.
For demand-side EE, states must require that EM&V plans that are developed for purposes of adjusting an emission rate under this final rule include several specific components. The EPA notes these components reflect existing provisions in a wide range of publicly or rate-payer funded EE programs and energy service company projects. One of these components state plans must require is a demonstration of how savings will be quantified and verified by applying industry best-practice protocols and guidelines, as well as an explanation of the key assumptions and data sources used. State plans must require EM&V plans to include and address the following:
• A baseline that represents what would have happened in the absence of the EE intervention, such as the equipment that would most likely have been installed—or that a typical consumer or building owner would have continued using—in a given circumstance at the time of EE implementation
• The effects of changes in independent factors affecting energy consumption and savings; that is, factors not directly related to the EE action, such as weather, occupancy, or production levels
• The length of time the EE action is anticipated to continue to remain in place and operable, effectively providing savings (in years)
Examples and discussion of industry best-practices for executing each of the above-listed components is provided in the EPA's draft EM&V guidance for demand-side EE, which is being released in conjunction with the proposed model rule. The model trading rule defines certain EM&V provisions for demand-side EE, as well as specific provisions for non-affected CHP and RE resources, including incremental hydroelectric power, biomass RE facilities, and waste-to-energy facilities,
The EPA notes that state plans incorporating the finalized model rule for rate-based emission trading programs could be presumptively approvable as meeting the requirements of CAA section 111(d) and the EM&V provisions in these emission guidelines. The EPA will evaluate the approvability of such state plans through independent notice and comment rulemaking.
c.
Using a skilled workforce to implement demand-side EE and RE projects and other measures intended to reduce CO
The EPA is therefore recommending in conjunction with the EM&V requirements discussed in this section, that states are encouraged to include in their plans a description of how states will ensure that the skills of workers installing demand-side EE and RE projects or other measures intended to reduce CO
(1) Develops a competency based program aligned with a job task analysis and certification scheme;
(2) Engages with subject matter experts in the development of the job task analysis and certification schemes that represent appropriate qualifications, categories of the jobs, and levels of experience;
(3) Has clearly documented the process used to develop the job task analysis and certification schemes, covering such elements as the job description, knowledge, skills, and abilities;
(4) Has pursued third-party accreditation aligned with consensus-based standards, for example ISO/IEC 17024.
Examples of such entities include: Parties aligned with the Department of Energy's (DOE) Better Building Workforce Guidelines and validated by a third party accrediting body recognized by DOE; or by an apprenticeship program that is registered with the federal Department of Labor (DOL), Office of Apprenticeship; or with a state apprenticeship program approved by the DOL, or by another skill certification validated by a third party accrediting body. This can help to substantiate the authenticity of emission reductions due to demand-side EE and RE and other CO
Individual rate-based state plans may provide for the interstate transfer of ERCs, which would enable an ERC issued by one state to be used for compliance by an affected EGU with a rate-based emission standard in another state. Such plans would include regulatory provisions in each state's emission standard requirements that indicate that ERCs issued in other partner states may be used by affected EGUs for compliance. Such plans must indicate how ERCs will be tracked from issuance through use for compliance, through either a joint tracking system, interoperable tracking systems, or an EPA-administered tracking system.
The approaches described in this section are only allowed for states that impose rate-based emission limits for affected EGUs that are equal to the CO
This approach avoids providing different incentives, in the form of issued ERCs, to affected steam generating units and NGCC units in different states that have comparable CO
When demonstrating that a state's CO
States could implement these linkages among state plans with rate-based emission trading systems through three different implementation approaches: (1) Plans that are “ready-for-interstate-trading;” (2) plans that include specified bilateral or multilateral linkages; and (3) plans that provide for joint ERC issuance among states with materially consistent regulations. These approaches are summarized below:
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These implementation approaches are designed to streamline the process for linking emission trading programs, avoid or limit the need for plan revisions as new states join a collaborative emission trading approach, and facilitate the development of regional or broader multi-state markets for ERCs.
This section discusses how differing characteristics across states and sources could create risks of increased emissions under this rule through double counting of emission reduction measures or through foregone emission reductions due to movement of generation from source to source. The section also discusses how the final rule addresses these concerns: First, through the characteristics of goal-setting and the framework of state plans, and second, through specific requirements intended to minimize the risk of double counting and increased emissions.
The section is structured as follows. First, this section discusses the dynamics that cause these risks to potentially arise. Second, it provides a discussion of how the risks of double counting and foregone reductions are minimized through the following provisions: The nature of the final emission performance rates, multi-state plan options that limit distortionary effects, the structure of mass-based plan and rate-based plan accounting for emission reductions measures, and specified restrictions on the counting in a rate-based plan of emission reduction measures located in a mass-based state. Finally, the section discusses how the rate-based accounting framework minimizes incentives to develop emission reduction measures in particular states due to differences in rates.
In the June 2014 proposal, the EPA acknowledged that emission reduction measures implemented under a state plan will likely have impacts across many affected sources both within and across state boundaries due to the dynamic and interstate nature of the electric grid. These interactions may be driven in part due to differences in power sector dynamics across states, including the types of affected EGUs in a state, the availability of eligible zero-emitting resources, and the costs of different compliance options and existing policies in states. These state-level characteristics play out across dynamic regional grids that provide electricity across states. EGUs are dispatched both within and across state borders and are constantly adjusting behavior in response to available generation and electricity demand on the regional grid. Whenever CO
In the context of this complex environment of federal and state policies and interstate grids, commenters expressed concern about the risk of double-counting of measure impacts, particularly across state plans. Commenters stated that there is potential for distortionary incentives that could undermine overall CO
The EPA acknowledges that some amount of shifts in generation between sources within and across state borders will inevitably be present and unavoidable in the context of this rule and may affect how affected EGUs achieve the applicable CO
In particular, the EPA has determined final emission performance rates that serve to reduce relative differences between state goals, and thus also focus the potential for generation shifting between affected EGUs on achieving the emission reductions quantified in the BSER. In the proposal, goals differed more substantially between states based upon an assessment of what emission reduction potential units could access located within their state. Commenters observed that due to the interconnected nature of the power sector, units are not limited to such emission reduction measures within their state, and indeed any operational decisions that units take necessarily influence operational decisions at other units throughout the interconnected grid. As a result, in the final rule, we are finalizing CO
The EPA has also incorporated elements into the rule that seek to minimize double-counting and the distortionary effects that could potentially increase emissions. First, states have the option to adopt multi-state plans that reflect regional interactions while eliminating chances for double counting and providing a level playing field for trading of rate-based ERCs or mass-based allowances. Second, in the method for rate-based plan compliance, the rule provides a general accounting approach for adjusting an affected EGU's or state's CO
For both rate-based and mass-based approaches, the rule provides states with the option of creating either “ready-for-interstate-trading” plans or multi-state plans. These options for states working together provide opportunities to enable protections against double counting and minimize the presence of distortionary effects.
“Ready-for-interstate-trading” and multi-state plans engage multiple states in the same system for the purpose of trading mass-based allowances or issuing and trading rate-based ERCs. This allows for efficient implementation of protections against double counting provided in state plan requirements, as multiple states are participating in the same tracking systems. This is particularly useful in the context of rate-based ERC issuance and tracking, where it must be ensured that the ERCs being generated are unique across rate-based plans.
This final rule also reduces distortionary effects within the context of multi-state plans. It does so by restricting states to interstate trading with equivalently denominated mass-based allowances or rate-based ERCs. In a mass-based context, all affected EGUs will trade uniform mass-based allowances, whether in a “ready-for-interstate-trading” plan or multi-state plan. In a rate-based plan context, “ready-for-interstate-trading” states must all adopt as their goal the CO
Under all types of state plans, states must ensure that the emission reduction measures counted as part of meeting their plan requirements are not duplicative of any measures that are counted by another state, in order to avoid double counting of the MWhs of generation or energy savings that these measure produce. Depending on the accounting method used to reflect these measures in state goals, interstate effects could still allow for the double counting of the emission reductions resulting from these measures, particularly if mathematical adjustments were made to stack emissions to reflect these reductions. Depending on how these measures are accounted for, the reductions could be counted by both the state that deployed the measure, and the state that reports a reduction in fossil generation or reported emissions. In this final rule, the accounting approaches for both mass-based and rate-based plans have been specifically designed to eliminate the risk of double counting of reductions, because emission reduction measures are accounted for only through their inherent impact on stack emissions for affected EGUs.
Mass-based plans rely exclusively on reported stack emissions for determining whether a mass-based CO
In a rate-based plan, there needs to be an explicit adjustment of reported CO
The general accounting approach for adjusting the CO
Double-counting of MWhs in the denominator can be avoided because it is relatively straightforward to quantify the MWhs that the affected EGU is responsible for deploying and add them to the denominator, and this method aligns well with the MWh-denominated trading system described in this final rule. As long as it is assured that the MWhs of RE and demand-side EE are only being claimed by one affected EGU or state, as is outlined in section VIII.K, then there is no double-counting of MWh. Therefore, the accounting method avoids double counting of both CO
There may also be interactions between mass-based and rate-based plans regarding counting measures, specifically where measures that provide substitute or avoided generation, such as RE and demand-side EE, are located in a mass-based state and can also be used by a rate-based state in meeting the CO
Commenters provided analyses specifying how two states can benefit from the same RE and demand-side EE measures as a result of rate- and mass-based plan interactions. Some commenters considered this double-counting of emission reductions, and requested specific mathematical adjustments of reported generation or CO
The EPA has determined that, in the context of interactions among rate-based and mass-based plans, there is not explicit double-counting of the CO
Though there is no risk of double-counting emissions, some commenters expressed the concern that overall CO
While the EPA understands this concern regarding foregone reductions, we do not believe it is appropriate to restrict RE crediting unilaterally between rate-based and mass-based states. Such a restriction could cut some states off from regional RE supplies that are assumed in the BSER building block 3 and incorporated in the CO
The following are examples of how requirements for a demonstration could be established in state plans and used to allow RE in a mass-based state to be counted in a rate-based state. For an emission standards state plan, a state could specify in the regulations for the rate-based emission standards included in its state plan that it will require an RE provider that seeks the issuance of ERCs to show that load-serving entities in the rate-based state have contracted for the delivery of the RE generation that occurs in a mass-based state to meet load in a rate-based state. Under this approach, an RE provider in a mass-based state could submit as part of an eligibility application a delivery contract or power purchase agreement showing that the generation was procured by the utility, and was treated as a generation resource used to serve regional load that included the rate-based state. This documentation would be sufficient demonstration to allow the RE generating resource to meet this additional geographic eligibility requirement for the amount of generation in question. All quantified and verified RE MWhs submitted for ERC issuance would need to be associated with that power purchase contract or agreement, and this fact would need to be demonstrated in the M&V reports submitted for issuance of ERCs.
The ability for a rate-based state to count MWhs located in a mass-based state under the above conditions is limited to RE. Rate-based states are not allowed to claim demand-side EE or any other emission reduction measures that were not included in the determination of the BSER located in mass-based states for ERC issuance. While this limits rate-based sources' access to additional resources, providing that access would result in a risk of foregone reductions. Further, unlike RE, there is no obligation related to demand-side EE and other measures that were not included in the determination of the BSER incorporated in the CO
Finally, as stated earlier, commenters also expressed concern about the potential for relative increases in emissions to occur given relative differences between sources and states. These differences could include states' goals under either the rate- or mass-based approaches, or states' accounting of new sources. These differences could induce increased generation in one state over another because the costs of compliance and relative costs of generation would vary between states. There was particular concern regarding how these differences would provide incentives for increasing generation at new fossil sources and expanding utilization of existing affected EGU generation in states that have less stringent goals, and that this movement of generation would result in increased emissions overall. This could potentially result in the achievement of performance rates but with fewer overall CO
Commenters suggested that the issuance and trading of emission credits across states under a rate-based approach would result in incentives to create credits, through the development of RE for example, in certain states with higher state goals, and this could also be a source of increased overall emissions. They noted that RE siting would thus not occur in the most optimal locations. The commenters assumed that zero-emitting credits are denominated in mass units by multiplying the number of MWh by some emission rate: Either the state goal rate, the current state emission rate, a regional emission rate, or a calculated marginal rate. If those rates were higher in any states, zero-emitting MWhs would create more mass-denominated credits in those states, and thus RE and demand-side EE would be more valuable.
The incentive to target the location of zero-emitting generation or energy savings between states based on variation in its emission reduction value has been minimized by the fact that states participating in rate-based interstate trading must adopt the same emission performance rates or rate-based state goals. It is further minimized, even outside of an interstate trading framework, by the nature of the accounting method finalized in this rule. As explained above regarding the general accounting approach and the trading framework, we are adjusting rates using calculated MWhs, not based upon an emission reduction approximation as commenters outlined above. Not only does the method allow emission reductions to be accounted for as they occur across the grid, but it means the ERCs being traded across states represent one MWh of zero-emitting generation in whatever state it originated, and its value is unaffected by any emission rate associated with its state of origin. Thus, the finalized accounting and trading methods minimize the relative incentives for generating zero-emitting ERCs in a particular state based upon the rates that apply to that state.
In this section we provide an overview of the actions that the agency is taking to help ensure that vulnerable communities are not disproportionately impacted by this rulemaking.
Vulnerable communities also often receive more than their fair share of conventional air pollution, with the attendant adverse health impacts. The changes in electricity generation that will result from this rule will further benefit communities by reducing existing air pollution that directly contributes to adverse localized health effects. These air quality improvements will be achieved through this rule because the electric generating units that emit the most GHGs also have the highest emissions of conventional pollutants, such as SO
By reducing millions of tons of CO
There are other ways in which the actions that result from this rulemaking may affect communities in positive or potentially adverse ways and we also heard about these from commenters.
While the agency expects overall emission decreases as a result of this
In addition to the many positive anticipated health benefits of this rulemaking, it also will increase the use of clean energy and will encourage EE. These changes in the electricity generation system, which are already occurring but may be accelerated by this program, are expected to have other positive benefits for communities. The electricity sector is, and will continue to be, investing more in RE and EE. The construction of renewable generation and the implementation of EE programs such as residential weatherization will bring investment and employment opportunities to the communities where they take place. We recognize that certain communities whose economies may be affected by changes in the utility and related sectors may be particularly impacted by the final rule. The EPA encourages states to make an effort to engage with these communities, including workers and their representatives in these sectors, including EE. It is important to ensure that all communities share in the benefits of this program. And while we estimate that its benefits will greatly exceed its costs (as noted in the RIA for this rulemaking), it is also important to ensure that to the extent there are increases in electricity costs, that those do not fall disproportionately on those least able to afford them.
The EPA has engaged with community groups throughout this rulemaking, and we received many comments on the issues outlined above from community groups, environmental justice organizations, faith-based organizations, public health organizations, and others.
It has also prompted us to work with our federal partners to make sure that states and communities have information on federal resources available to assist communities. We describe these resources below, as well as resources that the EPA will be providing to assist communities in accessing EE/RE and financial assistance programs. In our discussion below we also provide models of programs that other states are currently using to assist communities in accessing available resources that states could use when developing their plans.
Finally, and importantly, we recognize that communities must be able to participate meaningfully in state plan development. In this section, we discuss the requirements in the final rule for states, as they develop their plans, to provide opportunities for public involvement, and resources available to states and communities to enhance the success of the public process.
The EPA is committed to assisting states and communities to develop plans that ensure there are no disproportionate, adverse impacts on overburdened communities. To provide information fundamental to beginning that process, the EPA has conducted a proximity analysis for this final rulemaking that summarizes demographic data on the communities located near power plants.
The proximity analysis provides detailed demographic information on the communities located within a 3-mile radius of each affected power plant in the U.S. Included in the analysis is the breakdown by percentage of community characteristics such as income and minority status. The analysis shows a higher percentage of communities of color and low-income communities living near power plants than national averages. It is important to note that the impacts of power plant emissions are not limited to a 3-mile radius and the impacts of both potential increases and decreases in power plant emissions can be felt many miles away. Still, being aware of the characteristics of communities closest to power plants is a starting point in understanding how changes in the plant's air emissions may affect the air quality experienced by some of those already experiencing environmental burdens.
Although overall there is a higher fraction of communities of color and low-income populations living near power plants than national averages, there are differences between rural and urban power plants. There are many rural power plants that are located near small communities with high percentages of low-income populations and lower percentages of communities of color. In urban areas, nearby communities tend to be both low-income communities and communities of color. In light of this difference between rural and urban communities proximate to power plants and in order to adequately capture both the low-income and minority aspects central to environmental justice considerations, we use the terms “vulnerable” or “overburdened” when referring to these communities. Our intent is for these terms to be understood in an expansive sense, in order to capture the full scope of communities, including indigenous communities most often located in rural areas, that are central to our environmental justice and community considerations.
As stated in the Executive Order 12898 discussion located in section XII.J of this preamble, the EPA believes that all communities will benefit from this final rulemaking because this action directly addresses the impacts of climate change by limiting GHG emissions through the establishment of CO2 emission guidelines for existing affected fossil fuel-fired power plants.
Additionally, the EPA encourages states to conduct their own analyses of community considerations when developing their plans. Each state is uniquely knowledgeable about its own communities and well-positioned to consider the possible impacts of plans on vulnerable communities within its state. Conducting state-specific analyses would not only help states assess possible impacts of plan options, but it would also enhance a state's understanding of the means to engage these communities that would most effectively reach them and lead to valuable exchanges of information and concerns. A state analysis, together with the proximity analysis conducted by the EPA, would provide a solid foundation for engagement between a state and its communities.
Such state-specific analyses need not be exhaustive. An examination of the options a state is considering for its plan, and any projections of likely resulting increases in power plant emissions affecting low-income populations, communities of color populations, or indigenous communities, would be informative for communities. The analyses could include available air quality monitoring data and information from air quality models, and, if available, take into account information about local health vulnerabilities such as asthma rates or access to healthcare. Alternatively, a simple analysis may consider expected EGU utilization in geographic proximity to overburdened communities. The EPA will provide states with information on its publicly available environmental justice screening and mapping tool, EJ SCREEN, which they may use in conducting a state-specific analysis. The EPA will also provide states with resources containing examples of analyses that other states have conducted to examine the impacts of their programs on overburdened communities. Additionally, the EPA encourages states to submit a copy of their analysis if they choose to conduct one, with their initial and final plan submittals.
In sections VIII.D-E of this preamble, the EPA explains that states need to engage meaningfully with communities and other stakeholders during the initial and final plan submittal processes. Meaningful engagement includes outreach to vulnerable communities, sharing information and soliciting input on state plan development and on any accompanying assessments such as those described above, and selecting methods for engagement to support communities' involvement at critical junctures in plan formulation and implementation. This engagement also includes providing the public the opportunity to comment on the state's initial submittal and responding to significant comments received, including comments from vulnerable communities, as well as conducting a public hearing and responding to comments before a final state plan is submitted. Additionally, the EPA expects that states will conduct outreach meetings, which could include public hearings or listening sessions, before the initial submittal is made. The EPA also encourages states to provide background information about their proposed final state plan or their initial state plan in the appropriate languages in advance of their public hearing and at their public hearing. The EPA recommends that states provide translators and other resources at their public hearings, to ensure that members of the public can provide oral feedback.
In the initial submittal, the final rule requires that states provide information to the agency about the community engagement they have undertaken and the means by which they intend to involve vulnerable communities and other stakeholders as they develop their final plan. Furthermore, as noted in section VIII.E of this preamble, in determining if states are eligible for a 2-year extension for submission of final plans, the rule requires that states demonstrate how they are meaningfully engaging vulnerable communities and other interested stakeholders as part of their public participation process. The EPA consulted its May 2015,
The EPA is committed to supporting states in effectively engaging with communities as they develop and implement their plans. The EPA will provide training and other resources throughout the implementation process that will assist states and communities in understanding plan requirements and options for plan development. These trainings will be a continuation of those that the EPA has already conducted with communities and states both pre- and post-proposal. The EPA will reach out to a wide variety of community stakeholders, including groups representing environmental justice communities, faith-based organizations, academic organizations working with vulnerable and overburdened communities, affordable housing advocates, public health professionals, public health organizations, and other community stakeholders.
In addition to providing resources to states, the EPA encourages states to be aware of existing efforts undertaken by other states aimed at providing low-income communities access to financial and technical assistance programs for EE and RE, and to consider similar approaches that may make sense for their own states. The EPA encourages states to consider targeting economic development resources to communities that are likely to be negatively affected by ongoing changes in the utility and related sectors in support of efforts to diversify their economies, attract new sources of investment, and create new jobs.
One example of a program targeted at low-income communities is the
Another example of a program is EmPower New York, which provides no-cost energy solutions to low-income populations.
In 2013, the New York State Energy and Research Development Authority (NYSERDA) was able to secure a triple-A rated financial guarantee from the state's Clean Water State Revolving Fund (SRF) for a $24 million bond issue. Proceeds funded residential EE loans that were available to all utility customers, including low-income households. SRF eligibility was based on the beneficial impact of EE investment in reducing atmospheric deposition on impaired water bodies consistent with Section 319 of the Clean Water Act.
As discussed below, there are also many federal programs that can help low-income populations access the benefits of RE, EE, and the economic benefits of a cleaner energy economy.
In the coming months, the EPA will continue to provide information and resources for communities and states on existing federal, state, local, and other financial assistance programs to encourage EE/RE opportunities that are already available to communities. For example the EPA will provide a catalog of current or recent state and local programs that have successfully helped communities adopt EE/RE measures. The goal of these resources is to help vulnerable communities gain the benefits of this rulemaking by encouraging that states use these types of tools in their state plans. The use of these RE/EE tools can also help low-income households reduce their electricity consumption and bills.
The EPA recognizes the potential impacts that this rulemaking could have on jobs in communities. Therefore, in section VIII.G of this preamble, the EPA has outlined that states, in designing their state plans, should consider the effects of their plans on employment and overall economic development to realize the opportunities for economic growth and jobs that the plans offer. To the extent possible, states should try to assure that communities that may be expected to experience job losses can also take advantage of the opportunities for job growth or otherwise transition to healthy, sustainable economic growth (
Federal agencies have a history of bringing EE and RE to low-income communities. Earlier this summer, the Administration announced a new initiative to scale up access to solar energy and cut energy bills for all Americans, in particular low- and moderate-income communities, and to create a more inclusive solar workforce. As part of this new initiative, the U.S. Department of Energy (DOE), the U.S. Department of Housing and Urban Development (HUD), U.S. Department of Agriculture (USDA), and the EPA launched a National Community Solar Partnership to unlock access to solar energy for the nearly 50 percent of households and businesses that are renters or do not have adequate roof space to install solar systems, with a focus on low- and moderate-income communities. The Administration also set a goal to install 300 megawatts (MW) of RE in federally subsidized housing by 2020 and plants to provide technical assistance to make it easier to install solar energy on affordable housing, including clarifying how to use federal funding for EE and RE. To continue enhancing employment opportunities in the solar industry for all Americans, AmeriCorps is providing funding to deploy solar energy and create jobs in underserved communities, and DOE is working to expand solar energy education and opportunities for job training.
These recent announcements build on the many existing federal programs and resources available to improve EE and accelerate the deployment of RE in vulnerable communities. Some examples of these resources include: the Department of Energy's Weatherization Assistance Program, Health and Human Service's Low Income Home Energy Assistance Program, the Department of Agriculture's Energy Efficiency and Conservation Loan Program, High Cost Energy Grant Program, and the Rural Housing Service's Multi-Family Housing Program.
HUD supports EE improvements and the deployment of RE on affordable housing through its Energy Efficient Mortgage Program, Multifamily Property Assessed Clean Energy Pilot with the State of California, PowerSaver Program, and the use of Section 108 Community Development Block Grants. The Department of Treasury provides several tax credits to support RE development and EE in low-income communities, including the New Markets Tax Credit Program and the Low-Income Housing Tax Credit. The EPA's RE-Powering America's Land Initiative promotes the reuse of potentially contaminated lands, landfills and mine sites—many of which are in low-income communities—for RE through a combination of tailored redevelopment tools for communities and developers, as well as site-specific technical support. The EPA's Green
The federal government also has a number of programs to expand employment opportunities in the energy sector, including for underserved populations. Examples of these include HUD, DOE, and the Department of Education's “STEM, Energy, and Economic Development” program; DOE's Diversity in Science and Technology Advances National Clean Energy in Solar (DISTANCE-Solar) Program; Grid Engineering for Accelerated Renewable Energy Deployment (GEARED); the Department of Labor's Trade Adjustment Assistance Community College and Career Training (TAACCCT), Apprenticeship USA Advancing Apprenticeships in the Energy Field, Job Corps Green Training and Greening of Centers, and YouthBuild; and the EPA's Environmental Workforce Development and Job Training (EWDJT) program.
As outlined in the final Clean Power Plan, states and sources have continued obligations to meet all other CAA requirements addressing conventional pollutants. Because the CAA envisions control of these other pollutants as a continuous process (through provisions such as periodic review of the NAAQS and residual risk requirements under the MACT program), the EPA believes that the Clean Power Plan provides an opportunity for states to consider strategies for meeting future CAA planning obligations as they develop their plans under this rulemaking. Multi-pollutant strategies that incorporate criteria pollutant reductions over the planning horizons specific to particular states, jointly with strategies for reducing CO
Air quality in a given area is affected by emissions from nearby sources and may be influenced by emissions that travel hundreds of miles and mix with emissions from other sources.
Another effect of the final CO
For natural gas-fired EGUs, the EPA found that regulation of HAP emissions “is not appropriate or necessary because the impacts due to HAP emissions from such units are negligible based on the results of the study documented in the utility RTC.”
It is important to the EPA that the implementation of state plans be assessed in order to identify whether they cause any adverse impacts on communities already overburdened by disproportionate environmental harms and risks. The EPA will conduct its own assessment during the implementation phase of this rulemaking to determine whether the implementation of state plans developed pursuant to this rulemaking and other air quality rules are, in fact, reducing emissions and improving air quality in all areas or whether there are localized air quality impacts that need to be addressed under other CAA authorities. Furthermore, the
This training will include guidance in accessing the publicly available information that sources and states currently report that can help with ongoing assessments of state plan impacts. For example, unit-specific emissions data and air quality monitoring data are readily available. This information, together with the assessment that the EPA will conduct in the implementation phase of this rulemaking and other analyses that states may develop, will enable states and communities to monitor any disproportionate emissions that may result in adverse impacts and to address them.
The EPA is committed to helping ensure that this action will not have disproportionate adverse human health or environmental effects on vulnerable communities. Throughout the implementation phase of this rulemaking, the agency will continue to provide trainings and resources to assist communities and states as they engage with one another. Additionally, we will provide states with recommendations on best practices for engaging with vulnerable communities. The EPA, through its outreach efforts during implementation, will continue to solicit feedback from communities and states on topics for which they would like additional trainings and resources.
The EPA will also provide states with resources containing examples of analyses that other states have conducted to examine the impacts of their programs on vulnerable communities, as well as information on its publicly available environmental justice screening and mapping tool, EJ SCREEN. States are encouraged to use this preliminary information as well as other available information to conduct their own analyses. As described above, the EPA will assess the impacts of this rulemaking during its implementation. The EPA will house this assessment, along with the proximity analysis and other information generated throughout the implementation process, on its Clean Power Plan (CPP) Community Portal that will be linked to this rulemaking's Web site (
A more detailed discussion concerning the application of Executive Order 12898 in this rulemaking can be found in section XI.J of this preamble. A summary of the EPA's interactions with communities is in the EJ Screening Report for the Clean Power Plan, available in the docket of this rulemaking. Furthermore, the EPA's responses to public comments, including comments received from communities, are provided in the response to comments documents located in the docket for this rulemaking.
In summary, the EPA in this final rulemaking has designed an integrative approach that helps to ensure that vulnerable communities are not disproportionately impacted by this rulemaking. The proximity analysis that the agency has conducted for this rulemaking is a central component of this approach. Not only is the proximity analysis a useful tool to help identify overburdened communities that may be impacted by this rulemaking, states can use this tool as they engage with communities in the development of their plans, consider a multi-pollutant approach, help low-income communities access EE/RE and financial assistance programs and assess the impacts of their state plans. Additionally, in order to continue to ensure that vulnerable communities are not disproportionately impacted by this rulemaking, the EPA will also be conducting its own assessment during the implementation phase. Furthermore, the EPA will continue to engage with communities and states throughout the implementation phase of this rulemaking to help ensure that vulnerable communities are not disproportionately impacted.
The new source review (NSR) program is a preconstruction permitting program that requires major stationary sources of air pollution to obtain permits prior to beginning construction. The requirements of the NSR program apply both to new construction and to modifications of existing major sources. Generally, a source triggers these permitting requirements as a result of a modification when it undertakes a physical or operational change that results in a significant emission increase and a net emissions increase. NSR regulations define what constitutes a significant net emissions increase, and the concept is pollutant-specific. As a result of the decision in
As part of its CAA section 111(d) plan, a state may impose requirements that require an affected EGU to undertake a physical or operational change to improve the unit's efficiency that results in an increase in the unit's dispatch and an increase in the unit's annual emissions. If the emissions increase associated with the unit's changes exceeds the thresholds in the NSR regulations for one or more regulated NSR pollutants, including the netting analysis, the changes would trigger NSR.
While there may be instances in which an NSR permit would be required, we expect those situations to be few. As previously discussed in this preamble, states have considerable flexibility in selecting varied measures as they develop their plans to meet the goals of the emission guidelines. One of these flexibilities is the ability of the state to establish emission standards in their CAA section 111(d) plans in such a way so that their affected sources, in complying with those standards, in fact would not have emissions increases that trigger NSR. To achieve this, the state would need to conduct an analysis consistent with the NSR regulatory requirements that supports its determination that as long as affected sources comply with the emission standards in their CAA section 111(d) plan, the source's emissions would not increase in a way that trigger NSR requirements.
For example, a state could decide to use demand-side measures or increase reliance on RE as a way of reducing the future emissions of an affected source initially predicted (without such alterations) to increase its emissions as a result of a CAA section 111(d) plan requirement. In other words, a state plan's incorporation of expanded use of cleaner generation or demand-side measures could yield the result that units that would otherwise be projected to trigger NSR through a physical change that might result in increased dispatch would not, in fact, increase their emissions, due to reduced demand for their operation. The state could also, as part of its CAA section 111(d) plan, develop conditions for a source expected to trigger NSR that would limit the unit's ability to move up in the dispatch enough to result in a significant net emissions increase that would trigger NSR (effectively establishing a synthetic minor limit).
In addition, in this final rule, we have also adjusted the date of the period for mandatory reductions to 2022, instead of 2020, and provided states with flexibility with respect to the glide path. This obviates concerns that there is insufficient time for sources that may need permits to obtain them and allows additional planning time for these changes to be undertaken in a manner that does not trigger PSD. As a result of such flexibility and anticipated state involvement, we expect that a limited number of affected sources would trigger NSR when states implement their plans.
In the preamble to the June 18, 2014 proposal, the EPA discussed the issue of excessive title V fees resulting inadvertently as a consequence of the promulgation of the first section 111 standard to regulate GHGs. Specifically, the EPA explained that when the first section 111 standard is promulgated for GHGs, if we do not revise 40 CFR parts 70 and 71 (the operating permit rule), then certain permitting authorities would be required to charge emissions-based fees for GHGs, resulting in fees that would be far in excess of what is required to cover the reasonable costs of the permitting programs. To avoid this situation, the EPA proposed as part of the re-proposed carbon pollution standards for newly constructed fossil fuel-fired power plants (70 FR 1429-1519; January 8, 2014) to exempt GHGs from the list of air pollutants that are subject to fee calculation requirements under the operating permit rules. Also, we proposed several options to impose a smaller fee adjustment for GHGs that would be reasonable and designed to recover the costs of addressing GHGs in permitting without being excessive.
In a separate action in this issue of the
This title V fee issue is a one-time occurrence resulting from the promulgation of the first CAA section 111 standard to regulate GHGs (the standards of performance for new, modified, and reconstructed EGUs, also promulgated in this issue of the
In the proposal, the EPA discussed that the section 111 rules would have no effect on the applicability thresholds for GHG under the operating permit rules. After the proposal for this rulemaking was published, the U.S. Supreme Court issued its opinion in
With respect to title V, the Supreme Court said that EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a title V operating permit. In accordance with that decision, the D.C. Circuit's amended judgment vacated the title V regulations under review in that case to the extent that they require a stationary source to obtain a title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. The D.C. Circuit also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of
Fossil fuel-fired EGUs are, or potentially will be, impacted by several other recently finalized or proposed EPA rules.
On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to reduce emissions of toxic air pollutants from new and existing coal- and oil-fired EGUs. The MATS rule will reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel; and acid gases, including hydrochloric acid and hydrofluoric acid. These toxic air pollutants, also known as hazardous air pollutants or air toxics, are known to cause, or suspected of causing, damage nervous system damage, cancer, and other serious health effects. The MATS rule will also reduce SO
New or reconstructed EGUs (
Existing sources subject to the MATS rule were required to begin meeting the rule's requirements on April 16, 2015. Controls that will achieve the MATS performance standards are being installed on many units. Certain units, especially those that operate infrequently, may be considered not worth investing in given today's electricity market, and are closing. The final MATS rule provided a foundation on which states and other permitting authorities could rely in granting an additional, fourth year for compliance provided for by the CAA. States report that these fourth year extensions are being granted. In addition, the EPA issued an enforcement policy that provides a clear pathway for reliability-critical units to receive an administrative order that includes a compliance schedule of up to an additional year, if it is needed to ensure electricity reliability.
The CSAPR requires states to take action to improve air quality by reducing SO
On May 19, 2014, the EPA issued a final rule under section 316(b) of the Clean Water Act (CWA) (33 U.S.C. 1326(b)) (referred to hereinafter as the 316(b) rule.) The rule was published on August 15, 2014 (79 FR 48300; August 15, 2014), and became effective October 14, 2014. The 316(b) rule establishes new standards to reduce injury and death of fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities.
On December 19, 2014, the EPA issued the final rule for the disposal of coal combustion residuals from electric utilities. The rule provides a comprehensive set of requirements for the safe disposal of coal combustion residuals (CCRs), commonly known as coal ash, from coal-fired power plants. The CCR rule is the culmination of extensive study on the effects of coal ash on the environment and public health. The CCR rule establishes technical requirements for existing and
These regulations address the risks from coal ash disposal—leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments by establishing requirements for where CCR landfills and surface impoundments may be located, how they must be designed, operated and monitored, when they must be inspected, and how they must be closed and cared for after closure. Additionally, the CCR rule sets out recordkeeping and reporting requirements, as well as the requirement for each facility to establish and post specific information to a publicly-accessible Web site. The final rule also supports the responsible recycling of CCRs by distinguishing safe, beneficial use from disposal.
The EPA is reviewing public comments and working to finalize the proposed SE ELG rule which will impact existing fossil fuel-fired EGUs. In 2013, the EPA proposed the SE ELG rule (78 FR 34432; June 7, 2013) to strengthen the controls on discharges from certain steam electric power plants by revising technology-based effluent limitations guidelines and standards for the steam electric power generating point source category. The current regulations, which were last updated in 1982, do not adequately address the toxic pollutants discharged from the electric power industry, nor have they kept pace with process changes that have occurred over the last three decades. Existing steam electric power plants currently contribute 50-60 percent of all toxic pollutants discharged to surface waters by all industrial categories regulated in the U.S. under the CWA. Furthermore, power plant discharges to surface waters are expected to increase as pollutants are increasingly captured by air pollution controls and transferred to wastewater discharges. The proposed regulation, which includes new requirements for both existing and new generating units, would reduce impacts to human health and the environment by reducing the amount of toxic metals and other pollutants currently discharged to surface waters from power plants. The EPA intends to take final action on the proposed rule by September 30, 2015.
The EPA is endeavoring to enable EGUs to comply with applicable obligations under other power sector rules as efficiently as possible (
In addition to the power sector rules discussed above, the development of SIPs for criteria pollutants (ozone, PM
Regarding ozone, the proposal included a discussion of the June 6, 2013, proposed implementation rule for the 2008 ozone National Ambient Air Quality Standards (NAAQS), addressing the statutory requirements for areas EPA has designated as nonattainment for the 2008 ozone NAAQS. The final implementation rule for the 2008 ozone NAAQS was signed on February 13, 2015, and published on March 6, 2015, with an effective date of April 6, 2015. In general, the 2008 ozone NAAQS implementation rule interprets applicable statutory requirements and provides flexibility to states to minimize administrative burdens associated with developing and implementing plans to meet and maintain the NAAQS. The rule establishes due dates for attainment plans and clarifies attainment dates for each ozone nonattainment area according to its classification based on air quality thresholds, with attainment dates starting in July 2015 through July 2032 depending on an area's classification.
On November 25, 2014, the EPA Administrator signed the proposed rulemaking for the 2015 revisions to the ozone NAAQS. The proposal was published in the
The proposal also outlined the key implementation milestones requiring revised SIPs, with due dates starting in October 2018 for infrastructure and interstate transport SIPs, attainment plans due 2020-21, and attainment dates of 2020-37. The EPA is under a court order to finalize its review of the ozone NAAQS by October 1, 2015.
Some commenters expressed concern with the potential impact proposed revisions to the ozone NAAQS could have on state planning efforts and affected entities' ability to comply with any potentially new requirements associated with a revised ozone NAAQS and those related to the 111(d) emission guidelines. In particular, commenters raised issues with a potentially more stringent ozone standard and the permitting and state planning implications this may create. While there was no discussion of the proposed revisions to the ozone NAAQS in the 111(d) emission guidelines proposal, commenters expressed a desire for the EPA to coordinate promulgation of the final 111(d) emission guidelines (and any other climate regulations) with the potential revision to the ozone standard to provide certainty and flexibility for states and affected sources.
While it is premature to speculate about the outcome of the ozone NAAQS review and how a more stringent ozone NAAQS may impact sources of ozone precursor emissions, including EGUs, we believe the planning and compliance timeframes that would follow from a revised ozone NAAQS and the timeframes we are finalizing today for submittal of the CAA section 111(d) state plans will allow considerable time for coordination by states in the development of their respective plans, as needed. As stated in the proposal, the EPA is prepared to work with states to assist them in coordinating their efforts across these planning processes.
Regarding PM
There are currently only 9 areas designated nonattainment for the 2012 PM
Related to the SO
Regarding requirements under the regional haze program, several affected EGUs have deadlines in the 2016-2021 timeframe to install controls to comply with the Best Available Retrofit Technology (BART) and reasonable progress requirements of the Regional Haze Rule. Soon after these deadlines, some of the same affected EGUs may be required to reduce their utilization, convert into natural gas-fired facilities, or shut down entirely as a result of state 111(d) plans. Some commenters have expressed concern that for these affected EGUs, specifically those that choose to retire, the capital equipment installed to comply with the Regional Haze Rule would likely become stranded assets.
While the EPA is providing considerable flexibility for states and sources under the final 111(d) emission guidelines, the EPA acknowledges the possibility that some sources could ultimately be faced with the potential for stranded assets as a result of state 111(d) plans. For these sources, however, states have the option of developing BART alternatives that replace control requirements that would otherwise result in stranded assets at a particular EGU with the aggregate emission reductions that will result from retirements, fuel switching, reduced utilization, or lesser controls at multiple EGUs.
In fact, the EPA already has experience working with states to account for these very types of changed circumstances.
The EPA believes that CAA section 111(d) efforts and actions will tend to contribute to overall air quality improvements and thus should be complementary to criteria pollutant and regional haze SIP efforts.
As discussed in Section VIII of this preamble, the EPA is providing states flexibility in developing approvable plans under CAA section 111(d), including the ability to impose source-by-source limitations reflecting the BSER performance rates to each affected EGU or to adopt rate-based or mass-based emission performance goals, and to rely on a wide range of CO
In light of these broad flexibilities, we believe that states will have ample opportunity, when developing and implementing their CAA section 111(d) plans, to coordinate their response to this requirement with source and state responses to any obligations that may be applicable to affected EGUs as a result of the MATS, CSAPR, 316(b), SE ELG and CCR rules, all of which are or soon will be final rules. In addition, we believe that states will be able to design CAA section 111(d) plans that use innovative, cost-effective regulatory strategies, that spark investment and innovation across a wide variety of clean energy technologies, and that will help reduce cost and ensure reliability, while also ensuring that all applicable environmental requirements are met.
The EPA anticipates significant emission reductions under the final guidelines for the utility power sector. In the final emission guidelines, the EPA has translated the source category-specific CO
Under the rate-based approach, when compared to 2005, CO
The reductions in Tables 15 and 16 do not account for reductions in hazardous air pollutants (HAPs) that may occur as a result of this rule. For instance, the fine particulate reductions presented above do not reflect all of the reductions in many heavy metal particulates.
As explained in the preamble to the proposed rule (79 FR at 34933-934), the EPA has carefully considered the requirements of section 7(a)(2) of the Endangered Species Act (ESA) and applicable ESA regulations, and reviewed relevant ESA case law and guidance, to determine whether consultation with the U.S. Fish and Wildlife Service (FWS) and/or National Marine Fisheries Service (together, the Services) is required by the ESA. The EPA proposed to conclude that the requirements of ESA section 7(a)(2) would not be triggered by promulgation of the rule, and we now finalize that determination.
Section 7(a)(2) of the ESA requires federal agencies, in consultation with one or both of the Services (depending on the species at issue), to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of federally listed endangered or threatened species or result in the destruction or adverse modification of designated critical habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant implementing regulations, section 7(a)(2) applies only to actions where there is discretionary federal involvement or control. 50 CFR 402.03. Further, under the regulations consultation is required only for actions that “may affect” listed species or designated critical habitat. 50 CFR 402.14. Consultation is not required where the action has no effect on such species or habitat. Under this standard, it is the federal agency taking the action that evaluates the action and determines whether consultation is required.
The EPA notes that the projected environmental effects of this rule are positive: Reductions in overall GHG emissions, and reductions in PM and ozone-precursor emissions (SO
With respect to the projected GHG emission reductions, the EPA considered in detail in the proposal why such reductions do not trigger ESA consultation requirements under section 7(a)(2). As explained in the proposal, in reaching this conclusion the EPA was mindful of significant legal and technical analysis undertaken by FWS and the U.S. Department of the Interior (DOI) in the context of listing the polar bear as a threatened species under the ESA. In that context, in 2008, FWS and DOI expressed the view that the best scientific data available were insufficient to draw a causal connection between GHG emissions and effects on the species in its habitat.
As described in the proposal, the EPA has also previously considered issues relating to GHG emissions in connection with the requirements of ESA section 7(a)(2) and has supplemented DOI's analysis with additional consideration of GHG modeling tools and data regarding listed species. Although the GHG emission reductions projected for this final rule are large (estimated reductions of about 415 million short tons of CO
With regard to non-GHG air emissions, the EPA also projects substantial reductions of SO
Finally, the EPA has also considered other potential effects of the rule (beyond reductions in air pollutants) and whether any such effects are “caused by” the rule and “reasonably certain to occur” within the meaning of the ESA regulatory definition of the effects of an action. 50 CFR 402.02. As the EPA noted in the proposal, there are substantial questions as to whether any potential for relevant effects results from any element of the rule or would result instead from separate decisions and actions made in connection with the development, implementation, and enforcement of a plan to implement the standards established in the rule.
The EPA has carefully considered the comments and the correspondence from Congress as well as the case law and other materials cited in those documents. The EPA does not believe that the effects of potential future changes in the energy sector—including increased reliance on wind or solar power as a result of future potential actions by states or other implementing entities—or any potential alterations in the operations of any particular facility are caused by the current rule or sufficiently certain to occur so as to require ESA consultation on the rule. The EPA appreciates that the ESA regulations call for consultation where actions authorized, funded, or carried out by federal agencies may have indirect effects on listed species or designated critical habitat. However, as noted above, indirect effects must be caused by the action at issue and must be reasonably certain to occur. At this point, there is no reasonable certainty regarding implementation of any planning measures in any location, let alone in any location occupied by a listed species or its designated critical habitat. The EPA cannot predict with reasonable certainty where such measures may take effect or which measures may be adopted. It is not clear, for instance, whether a particular implementation plan will call, if at all, for increased reliance on wind power, as opposed to solar power, or on some other form of low or zero carbon emitting generation. It is also entirely uncertain how a future implementation plan for a particular state might affect, if at all, operations at a specific facility.
The final guidelines have important energy market implications. Table 17 presents a variety of important energy market impacts for 2020, 2025, and 2030 under both the rate-based and mass-based illustrative plan approaches.
These figures reflect the EPA's illustrative modeling that presumes policies that lead to generation shifts and growing use of demand-side EE and renewable electricity generation out to 2029. If states make different policy choices, impacts could be different. For instance, if states implement renewable and/or demand-side EE policies on a more aggressive time-frame, impacts on natural gas and electricity prices would likely be less. Implementation of other measures not included in the BSER calculation or compliance modeling, such as nuclear uprates, transmission system improvements, use of energy storage technologies or retrofit CCS, could also mitigate gas price and/or electricity price impacts.
Energy market impacts from the guidelines are discussed more extensively in the RIA found in the docket for this rulemaking.
The compliance costs of this final action are represented in this analysis as the change in electric power generation costs between the base case and the final rule in which states pursue a distinct set of strategies beyond the strategies taken in the base case to meet the terms of the final guidelines. The compliance costs estimates include cost estimates for demand-side EE. The compliance assumptions—and, therefore, the projected compliance costs—set forth in this analysis are illustrative in nature and do not represent the full suite of compliance flexibilities states may ultimately pursue. The illustrative analysis is designed to reflect, to the extent possible, the scope and the nature of the final guidelines. However, there is considerable uncertainty with regards to the precise measures that states will adopt to meet the final requirements, because there are considerable flexibilities afforded to the states in developing their state plans.
The incremental cost is the projected additional cost of complying with the guidelines in the year analyzed and includes the amortized cost of capital investment, needed new capacity, shifts between or amongst various fuels, deployment of demand-side EE programs, and other actions associated with compliance. These important
The EPA estimates the annual incremental compliance cost for the rate-based approach for final emission guidelines to be $2.5 billion in 2020, $1.0 billion in 2025 and $8.4 billion in 2030, including the costs associated with monitoring, reporting, and recordkeeping (MR&R).
More detailed cost estimates are available in the RIA included in the rulemaking docket.
The final standards are projected to result in certain changes to power system operation as a compliance with the standards. See Table 16 above for a variety of important energy market impacts for 2020, 2025, and 2030 under both the rate-based and mass-based illustrative plan approaches.
It is important to note that the EPA's modeling does not necessarily account for all of the factors that may influence business decisions regarding future coal-fired capacity. Many power companies already factor a potential financial liability associated with carbon emissions into their long term capacity planning that would further influence business decisions to replace these aging assets with modern, and significantly cleaner, generation.
The compliance modeling done to support the final rule assumes that overall electric demand will decrease as states ramp up programs that result in lower overall demand. Demand-side EE levels are expected to increase such that they achieve about a 7.8 percent reduction on overall electricity demand levels in 2030 under the final guidelines.
Changes in price or demand for electricity, natural gas, and coal can impact markets for goods and services produced by sectors that use these energy inputs in the production process or supply those sectors. Changes in the cost of production may result in changes in prices, quantities produced, and profitability of affected firms. The EPA recognizes that these guidelines provide significant flexibilities and states implementing the guidelines may choose to mitigate impacts to some markets outside the utility power sector. Similarly, demand for new generation or demand-side EE as a result of states implementing the guidelines can result in shifts in production and profitability for firms that supply those goods and services.
Executive Order 13563 directs federal agencies to consider the effect of regulations on job creation and employment. According to the Executive Order, “our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation. It must be based on the best available science.” (Executive Order 13563, 2011) Although standard benefit-cost analyses have not typically included a separate analysis of regulation-induced employment impacts, we typically conduct employment analyses. While the economy continues moving toward full-employment, employment impacts are of particular concern and questions may arise about their existence and magnitude.
States have the responsibility and flexibility to implement policies and practices for compliance with the final guidelines. Quantifying the associated employment impacts is complicated by the wide range of approaches that states may use. As such, the EPA's employment analysis includes projected employment impacts associated with illustrative plan approaches for these guidelines for the electric power industry, coal and natural gas production, and demand-side EE activities. These projections are derived, in part, from a detailed model of the utility power sector used for this regulatory analysis, and U.S government data on employment and labor productivity. In the electricity, coal, and natural gas sectors, the EPA estimates that these guidelines could result in a net decrease of approximately 25,000 job-years in 2025 for the final guidelines under the rate-based illustrative plan approach and approximately 26,000 job-years in 2025 under the mass-based approach. For 2030, the estimates of the net decrease in job-years are 31,000 under the rate-based approach and 34,000 under the mass-based approach. The agency is also offering an illustrative calculation of potential employment effects due to demand-side EE programs. Employment impacts from demand-side energy EE programs in 2030 could range from approximately 52,000 to 83,000 jobs under the final guidelines.
By its nature, demand-side EE reduces overall demand for electric power. The EPA recognizes as more efficiency is built into the U.S. power system over time, lower fuel requirements may lead to fewer jobs in the coal and natural gas extraction sectors, as well as in fossil-fuel fired EGU construction and operation than would otherwise have been expected. The EPA also recognizes the fact that, in many cases, employment gains and losses that might be attributable to this rule would be expected to affect different sets of people. Moreover, workers who lose jobs in these sectors may find employment elsewhere just as workers employed in new jobs in these sectors may have been previously employed elsewhere. Therefore, the employment estimates reported in these sectors may include workers previously employed elsewhere. This analysis also does not capture potential economy-wide impacts due to changes in prices (of fuel, electricity, labor, for example) or other factors such as improved labor productivity and reduced health care expenditures resulting from cleaner air. For these reasons, the numbers reported here should not be interpreted as a net national employment impact.
Implementing the final standards will generate benefits by reducing emissions of CO
The EPA has used the social cost of carbon (SC-CO
The SC-CO
The EPA received numerous comments on the SC-CO
Concurrent with OMB's publication of the response to comments on SC-CO
The EPA, as a member of the IWG on the SC-CO
The four SC-CO
There are limitations in the estimates of the benefits from the final emission guidelines, including the omission of climate and other CO
The health co-benefits estimates represent the total monetized human health benefits for populations exposed to reduced PM
PM benefit-per-ton values are generated using two concentration-response functions, Krewski et al. (2009)
It is important to note that the magnitude of the PM
For the ozone co-benefits, we present the results as a range reflecting benefit-per-ton estimates which use several different concentration-response functions for mortality, with the lower end of the range based on a benefit-per-ton estimate using the function from Bell et al. (2004)
In this analysis, in estimating the benefits-per-ton for PM
In general, we are more confident in the magnitude of the risks we estimate from simulated PM
For this analysis, policy-specific air quality data are not available,
Every benefit analysis examining the potential effects of a change in environmental protection requirements is limited, to some extent, by data gaps, model capabilities (such as geographic coverage) and uncertainties in the underlying scientific and economic studies used to configure the benefit and cost models. Despite these uncertainties, we believe the air quality co-benefit analysis for this rule provides a reasonable indication of the expected health benefits of the air pollution emission reductions for the illustrative analysis of the final standards under a set of reasonable assumptions. This analysis does not include the type of detailed uncertainty assessment found in the 2012 PM
We note that the monetized co-benefits estimates shown here do not include several important benefit categories, including exposure to SO
For more information on the benefits analysis, please refer to the RIA for this rule, which is available in the rulemaking docket.
Additional information about these Statutory and Executive Orders can be found at
This final action is an economically significant regulatory action that was submitted to the OMB for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, which is contained in the “Regulatory Impact Analysis for Clean Power Plan Final Rule” (EPA-452/R-15-003, July 2015), is available in the docket and is briefly summarized in section XI of this preamble.
Consistent with Executive Order 12866 and Executive Order 13563, the EPA estimated the costs and benefits for illustrative compliance approaches of implementing the guidelines. The final rule establishes: (1) Carbon dioxide (CO
The EPA has used the social cost of carbon estimates presented in the
In the final emission guidelines, the EPA has translated the source category-
It is very important to note that the differences between the analytical results for the rate-based and mass-based illustrative plan approaches presented in the RIA may not be indicative of likely differences between the approaches if implemented by states and affected EGUs in response to the final guidelines. Rather, the two sets of analyses are intended to illustrate two different approaches to accomplish the emission performance rates finalized in the Clean Power Plan Final Rule. In other words, if one approach performs differently than the other on a given metric during a given time period, this does not imply this will apply in all instances in all time periods in all places.
The EPA estimates that, in 2020, the final guidelines will yield monetized climate benefits (in 2011$) of approximately $2.8 billion for the rate-based approach and $3.3 billion for the mass-based approach (3 percent model average). For the rate-based approach, the air pollution health co-benefits in 2020 are estimated to be $0.7 billion to $1.8 billion (2011$) for a 3 percent discount rate and $0.64 billion to $1.7 billion (2011$) for a 7 percent discount rate. For the mass-based approach, the air pollution health co-benefits in 2020 are estimated to be $2.0 billion to $4.8 billion (2011$) for a 3 percent discount rate and $1.8 billion to $4.4 billion (2011$) for a 7 percent discount rate. The annual, illustrative compliance costs estimated by IPM and inclusive of demand-side EE program and participant costs and MRR costs in 2020, are approximately $2.5 billion for the rate-based approach and $1.4 billion for the mass-based approach (2011$). The quantified net benefits (the difference between monetized benefits and compliance costs) in 2020 are estimated to range from $1.0 billion to $2.1 billion (2011$) for the rate-based approach and from $3.9 billion to 6.7 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average).
The EPA estimates that, in 2025, the final guidelines will yield monetized climate benefits (in 2011$) of approximately $10 billion for the rate-based approach and $12 billion for the mass-based approach (3 percent model average). For the rate-based approach, the air pollution health co-benefits in 2025 are estimated to be $7.4 billion to $18 billion (2011$) for a 3 percent discount rate and $6.7 billion to $16 billion (2011$) for a 7 percent discount rate. For the mass-based approach, the air pollution health co-benefits in 2025 are estimated to be $7.1 billion to $17 billion (2011$) for a 3 percent discount rate and $6.5 billion to $16 billion (2011$) for a 7 percent discount rate. The annual, illustrative compliance costs estimated by IPM and inclusive of demand-side EE program and participant costs and MRR costs in 2025, are approximately $1.0 billion for the rate-based approach and $3.0 billion for the mass-based approach (2011$). The quantified net benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated to range from $17 billion to $27 billion (2011$) for the rate-based approach and $16 billion to $26 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average).
The EPA estimates that, in 2030, the final guidelines will yield monetized climate benefits (in 2011$) of approximately $20 billion for the rate-based approach and $20 billion for the mass-based approach (3 percent model average). For the rate-based approach, the air pollution health co-benefits in 2030 are estimated to be $14 billion to $34 billion (2011$) for a 3 percent discount rate and $13 billion to $31 billion (2011$) for a 7 percent discount rate. For the mass-based approach, the air pollution health co-benefits in 2030 are estimated to be $12 billion to $28 billion (2011$) for a 3 percent discount rate and $11 billion to $26 billion (2011$) for a 7 percent discount rate. The annual, illustrative compliance costs estimated by IPM and inclusive of demand-side EE program and participant costs and MRR costs in 2030, are approximately $8.4 billion for the rate-based approach and $5.1 billion for the mass-based approach (2011$). The quantified net benefits (the difference between monetized benefits and compliance costs) in 2030 are estimated to range from $26 billion to $45 billion (2011$) for the rate-based approach and from $26 billion to $43 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average).
Tables 20 and 21 provide the estimates of the climate benefits, health co-benefits, compliance costs and net benefits of the final emission guidelines for rate-based and mass-based illustrative plan approaches, respectively.
There are additional important benefits that the EPA could not monetize. Due to current data and modeling limitations, our estimates of the benefits from reducing CO
The information collection requirements in this rule have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document prepared by the EPA has been assigned the EPA ICR number 2503.02. 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 rule does not directly impose specific requirements on EGUs located in states or areas of Indian country. The rule also does not impose specific requirements on tribal governments that have affected EGUs located in their area of Indian country. For areas of Indian country, the rule establishes CO
This rule does impose specific requirements on state governments with affected EGUs. The information collection requirements are based on the recordkeeping and reporting burden associated with developing, implementing, and enforcing a plan to limit CO
The annual burden for this collection of information for the states (averaged over the first 3 years following promulgation) is estimated to be a range of 505,000 to 821,000 hours at a total annual labor cost of $35.8 to $58.1 million. The lower bound estimate reflects the assumption that some states already have EE and RE programs in place. The higher bound estimate reflects the overly-conservative assumption that no states have EE and RE programs in place.
The total annual burden for the federal government associated with the state collection of information (averaged over the first 3 years following promulgation) is estimated to be 54,000 hours at a total annual labor cost of $3.00 million. Burden is defined at 5 CFR 1320.3(b).
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the agency will announce that approval in the
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. This action will not impose any requirements on small entities. Specifically, emission guidelines established under CAA section 111(d) do not impose any requirements on regulated entities and, thus, will not have a significant economic impact upon a substantial number of small entities. After emission guidelines are promulgated, states establish emission standards on existing sources, and it is those requirements that could potentially impact small entities.
Our analysis here is consistent with the analysis of the analogous situation arising when the EPA establishes NAAQS, which do not impose any requirements on regulated entities. As here, any impact of a NAAQS on small entities would only arise when states take subsequent action to maintain and/or achieve the NAAQS through their SIPs. See
Nevertheless, the EPA is aware that there is substantial interest in the rule among small entities and, as detailed in section III.A of the preamble to the proposed carbon pollution emission guidelines for existing EGUs (79 FR 34845-34847; June 18, 2014) and in section II.D of the preamble to the proposed carbon pollution emission guidelines for existing EGUs in Indian Country and U.S. Territories (79 FR 65489; November 4, 2014), has conducted an unprecedented amount of stakeholder outreach. As part of that outreach, agency officials participated in many meetings with individual utilities and electric utility associations, as well as industry leaders and trade association representatives from various industries. While formulating the provisions of the rule, the EPA considered the input provided over the course of the stakeholder outreach as well as the input provided in the many public comments.
This action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. The emission guidelines do not impose any direct compliance requirements on EGUs located in states or areas of Indian country. As explained in section XII.B above, the rule also does not impose specific requirements on tribal governments that have affected EGUs located in their area of Indian country. The rule does impose specific requirements on state governments that have affected EGUs. Specifically, states are required to develop plans to implement the guidelines under CAA section 111(d) for affected EGUs. The burden for states to develop CAA section 111(d) plans in the 3-year period following promulgation of the rule was estimated and is listed in section XII.B above, but this burden is estimated to be below $100 million in any one year. Thus, this rule is not subject to the requirements of section 202 or section 205 of the UMRA.
This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. Specifically, the state governments to which rule requirements apply are not considered small governments.
In light of the interest among governmental entities, the EPA conducted outreach with national organizations representing state and local elected officials and tribal governmental entities while formulating the provisions of this rule. Sections III.A and XI.F of the preamble to the proposed carbon pollution emission guidelines for existing EGUs (79 FR 34845-34847; June 18, 2014) and sections II.D and VI.F of the preamble to the proposed carbon pollution emission guidelines for existing EGUs in areas of Indian Country and U.S. Territories (79 FR 65489; November 4, 2014) describes the extensive stakeholder outreach the EPA has conducted on setting emission guidelines for existing EGUs. The EPA considered the input provided over the course of the stakeholder outreach as well as the input provided in the many public comments when developing the provisions of these emission guidelines.
The EPA has concluded that this action may have federalism implications, pursuant to agency policy for implementing the Order, because it imposes substantial direct compliance costs on state or local governments, and the federal government will not provide the funds necessary to pay those costs. As discussed in the Supporting Statement found in the docket for this rulemaking, the development of state plans will entail many hours of staff time to develop and coordinate programs for compliance with the rule, as well as time to work with state legislatures as appropriate, to develop a plan submittal. Consistent with this determination, the EPA provides the following federalism summary impact statement.
The EPA consulted with state and local officials early in the process of developing the proposed action to permit them to have meaningful and timely input into its development. As described in the Federalism discussion in the preamble to the proposed standards of performance for GHG emissions from new EGUs (79 FR 1501; January 8, 2014), the EPA consulted with state and local officials in the process of developing the proposed standards for newly constructed EGUs. This outreach addressed planned actions for new, reconstructed, modified and existing sources. The EPA invited the following 10 national organizations representing state and local elected officials to a meeting on April 12, 2011, in Washington, DC: (1) National Governors Association; (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, (8) National Association of Towns and Townships, (9) County Executives of America, and (10) Environmental Council of States. The National Association of Clean Air Agencies also participated. On February 26, 2014, the EPA re-engaged with those governmental entities to provide a pre-proposal update on the emission guidelines for existing EGUs and emission standards for modified and reconstructed EGUs. In addition, as described in section III.A of the preamble to the proposed carbon pollution emission guidelines for existing EGUs (79 FR 34845-34847; June 18, 2014), extensive stakeholder outreach conducted by the EPA allowed state leaders, including governors, state attorneys general, environmental commissioners, energy officers, public utility commissioners, and air directors, opportunities to engage with EPA officials and provide input regarding reducing carbon pollution from power plants.
In the spirit of Executive Order 13132, and consistent with the EPA's policy to promote communications between the EPA and state and local governments, the EPA specifically solicited comment on the proposed action from state and local officials. The EPA received comments from over 400 entities representing state and local governments.
Several themes emerged from state and local government comments. Commenters raised concerns with the building blocks that comprise the best system of emission reduction (BSER), including the stringency of the building blocks, and the timing of achieving interim CO
Commenters identified overarching concerns regarding the stringency of the CO
To many commenters, the proposal's 2020 compliance date, together with the stringency of the interim CO
Commenters provided compelling information indicating that it will take longer than the agency initially anticipated to for states to complete the tasks necessary to finalize a state plan, including administrative and potential legislative processes. Recognizing this, as well as the urgent need for actions to reduce GHG emissions, the EPA is requiring states to make an initial submittal by September 6, 2016, and is allowing states two additional years to
States commented on state plan development and implementation topics that included state plan approaches, early actions being taken into account, trading programs being allowed, interstate crediting for RE being allowed, and guidance and outreach being provided by the EPA. For the state plan approaches, commenters expressed concerns with the proposed “portfolio approach” for state plans, including concerns with enforceability of requirements, and identified a “state commitment approach” with backstop measures as an option for state plans. In this final rule, in response to stakeholder comments on the portfolio approach and alternative approaches, the EPA is finalizing a “state measures” approach that includes a requirement for the inclusion of backstop measures.
State commenters supported providing incentives for states and utilities to deploy CO
Many state commenters supported the use of mass-based and rate-based emission trading programs in state plans, including interstate emission trading programs. The EPA also received a number of comments from states and stakeholders about the value of EPA support in developing and/or administering tracking systems to support state administration of rate-based and mass-based emission trading programs. In this final rule, states may use trading or averaging approaches and technologies or strategies that are not explicitly mentioned in any of the three building blocks as part of their overall plans, as long as they achieve the required emission reductions from affected fossil-fuel-fired EGUs. In addition, in response to concerns from states and power companies that the need for up-front interstate cooperation in developing multi-state plans could inhibit the development of interstate programs that could lower cost, the final rule provides additional options to allow individual EGUs to use creditable out-of-state reductions to achieve required CO
In their comments, many states identified the need for the EPA to provide guidance, including guidance on RE and EE emission measurement and verification (EM&V), and to maintain regular contact/forums with states throughout the implementation process. To provide state and local governments and other stakeholders with an understanding of the rule requirements, and to provide efficiencies where possible and reduce the cost and administrative burden, the EPA will continue outreach throughout the plan development and submittal process. Outreach will include opportunities for states to participate in briefings, teleconferences, and meetings about the final rule. The EPA's 10 regional offices will continue to be the entry point for states and tribes to ask technical and policy questions. The agency will host (or partner with appropriate groups to co-host) a number of webinars about various components of the final rule during the first two months after the final rule is issued. The EPA will use information from this outreach process to inform the training and other tools that will be of most use to the states and tribes that are implementing the final rule. The EPA expects to issue guidance on specific topics, including evaluation, measurement and verification (EM&V) for RE and demand-side EE, state-community engagement, and resources and financial assistance for RE and demand-side EE. As guidance documents, tools, templates and other resources become available, the EPA, in consultation with the U.S. Department of Energy and other federal agencies, will continue to make these resources available via a dedicated Web site.
A list of the state and local government commenters has been provided to OMB and has been placed in the docket for this rulemaking. In addition, the detailed response to comments from these entities is contained in the EPA's response to comments document on this final rulemaking, which has also been placed in the docket for this rulemaking.
As required by section 8(a) of Executive Order 13132, the EPA included a certification from its Federalism Official stating that the EPA had met the Executive Order's requirements in a meaningful and timely manner when it sent the draft of this final action to OMB for review pursuant to Executive Order 12866. A copy of the certification is included in the public version of the official record for this final action.
This action has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law. Tribes are not required to develop or adopt CAA programs, but they may apply to the EPA for treatment in a manner similar to states (TAS) and, if approved, do so. As a result, tribes are not required to develop plans to implement the guidelines under CAA section 111(d) for affected EGUs in their areas of Indian country. To the extent that a tribal government seeks and attains TAS status for that purpose, these emission guidelines would require that planning requirements be met and emission management implementation plans be executed by the tribes. The EPA notes that this rule does not directly impose specific requirements on affected EGUs, including those located in areas of Indian country, but provides guidance to any tribe approved by the EPA to address CO
As described in sections III.A and XI.F of the preamble to the proposed carbon pollution emission guidelines for existing EGUs (79 FR 34845-34847; June 18, 2014) and sections II.D and VI.F of the preamble to the proposed carbon pollution emission guidelines for existing EGUs in Indian Country and U.S. Territories (79 FR 65489; November 4, 2014), the rule was developed after extensive and vigorous outreach to tribal governments. These tribes expressed varied points of view. Some tribes raised concerns about the impacts of the regulations on EGUs located in their areas of Indian country and the subsequent impact on jobs and revenue for their tribes. Other tribes expressed concern about the impact the regulations would have on the cost of water covered under treaty to their communities as a result of increased costs to the EGU that provide energy to transport the water to the tribes. Other tribes raised concerns about the impacts of climate change on their communities, resources, ways of life and hunting and treaty rights. The tribes were also interested in the scope of the guidelines being considered by the agency (
The EPA consulted with tribal officials under the EPA Policy on Consultation and Coordination with Indian Tribes early in the process of developing this action to permit them to have meaningful and timely input into its development. A summary of that consultation follows.
Prior to issuing the supplemental proposal on November 4, 2014, the EPA consulted with tribes as follows. The EPA held a consultation with the Ute Tribe, the Crow Nation, and the Mandan, Hidatsa, Arikara (MHA) Nation on July 18, 2014. On August 22, 2014, the EPA held a consultation with the Fort Mojave Tribe. On September 15, 2014, the EPA held a consultation with the Navajo Nation. The Navajo Nation sent a letter to the EPA on September 18, 2014, summarizing the information presented at the consultation and the Navajo Nation's position on the supplemental proposal. One issue raised by tribal officials was the potential impacts of the June 18, 2014 proposal and the supplemental proposal on tribes with budgets that are dependent on revenue from coal mines and power plants, as well as employment at the mines and power plants. The tribes noted the high unemployment rates and lack of access to basic services on their lands. Tribal officials also asked whether the rules will have any impact on a tribe's ability to seek TAS. Tribal officials also expressed interest in agency actions with regard to facilitating power plant compliance with regulatory requirements. The Navajo Nation made the following recommendations in their letter of September 18, 2014: The Navajo Nation supports a mass-based CO
After issuing the supplemental proposal, the EPA held additional consultation with tribes. On November 18, 2014, the EPA held consultations with the following tribes: Fort McDowell Yavapai Nation, Fort Mojave Tribe, Hopi Tribe, Navajo Nation, and Ak-Chin Indian Community. A consultation with the Ute Indian Tribe of the Uintah and Ouray Reservation was held on December 16, 2014 and with the Gila River Indian Community on January 15, 2015. The Navajo Nation reiterated the concerns raised during the previous consultation. Several tribes also again indicated that they wanted to ensure they would be included in the development of any tribal or federal plans for areas of Indian country. The Fort Mojave Tribe and the Navajo Nation expressed concern with using data from 2012 as the basis for the goal for their areas of Indian country; in their view, that year was not representative for the affected EGU. On April 28, 2015, the EPA held an additional consultation with the Navajo Nation. The issues raised by the Navajo Nation during the consultation included whether the EPA has the authority to set less stringent standards on a case-by-case basis, and a suggested “parity glide path” that would account and adjust for the very low electricity usage by the Navajo Nation and promote Navajo Nation economic growth and demand. Furthermore, on July 7, 2015 the EPA conducted an additional consultation with the Navajo Nation. One of the goals of the consultation was for the new government of the Navajo Nation to deepen their understanding of the rulemaking. The questions raised by the nation had to do with goal setting and carbon credits, the timing of the rulemaking, and the proposed federal plan. Additionally, on July 14, 2015 the EPA conducted an additional consultation with the Fort Mojave Tribe. The Fort Mojave tribes expressed concerns that 2012 is not a representative year, that natural gas-fired combined cycle power plants should be treated differently from coal-fired power plants, and that the proposed goal for Fort Mojave was not appropriate. Additionally, they also expressed interest in being engaged in the federal plan process. Responses to these comments and others received are available in the Response to Comment Document that is in the docket for this rulemaking. As required by section 7(a), the EPA's Tribal Consultation Official has certified that the requirements of the executive order have been met in a meaningful and timely manner. A copy of the certification is included in the docket for this action.
This action is subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it is an economically significant regulatory action as defined by Executive Order 12866, and the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children.
CO
The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that certain populations and lifestages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience.
These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
More detailed information on the impacts of climate change to human health and welfare is provided in section II.A of this preamble.
This action, which is a significant regulatory action under EO 12866, is likely to have a significant effect on the supply, distribution, or use of energy. The EPA has prepared a Statement of Energy Effects for this action as follows. We estimate a 1 to 2 percent change in retail electricity prices on average across the contiguous U.S. in 2025, and a 22 to 23 percent reduction in coal-fired electricity generation as a result of this rule. The EPA projects that utility power sector delivered natural gas prices will increase by up to 2.5 percent in 2030. For more information on the estimated energy effects, please refer to the economic impact analysis for this proposal. The analysis is available in the RIA, which is in the public docket.
This rulemaking does not involve technical standards.
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA has this goal for all communities and persons across this Nation. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn, and work.
Leading up to this rulemaking the EPA summarized the public health and welfare effects of GHG emissions in its 2009 Endangerment Finding. See, section VIII.A of this preamble where the EPA summarizes the public health and welfare impacts from GHG emissions that were detailed in the 2009 Endangerment Finding under CAA section 202(a)(1).
The record for the 2009 Endangerment Finding summarizes the strong scientific evidence in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies that the potential impacts of climate change raise environmental justice issues. These reports concluded that poor communities can be especially vulnerable to climate change impacts because they tend to have more limited adaptive capacities and are more dependent on climate-sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particularly those impacted by degradation of natural and cultural resources within established reservation boundaries and threats to traditional subsistence lifestyles. Tribal communities whose health, economic well-being, and cultural traditions that depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. The 2009 Endangerment Finding record also specifically noted that Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities are already experiencing disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods and well-being.
The most recent assessments continue to strengthen scientific understanding of climate change risks to minority populations and low-income populations in the U.S.
IPCC, 2014:
As the scientific literature presented above and as the 2009 Endangerment Finding illustrates, low income populations and some communities of color are especially vulnerable to the health and other adverse impacts of climate change. The EPA believes that communities will benefit from this final rulemaking because this action directly addresses the impacts of climate change
In addition to reducing CO
Additionally, as outlined in the community and environmental justice considerations section IX of this preamble, the EPA has taken a number of actions to help ensure that this action will not have potential disproportionately high and adverse human health or environmental effects on overburdened communities. The EPA consulted its May 2015,
This final 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 a “major rule” as defined by 5 U.S.C. 804(2).
The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, title 40, chapter I, part 60 of the Code of the Federal Regulations is amended as follows:
42 U.S.C. 7401
This subpart establishes emission guidelines and approval criteria for State or multi-State plans that establish emission standards limiting greenhouse gas (GHG) emissions from an affected steam generating unit, integrated gasification combined cycle (IGCC), or stationary combustion turbine. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected EGU. These emission guidelines are developed in accordance with section 111(d) of the Clean Air Act and subpart B of this part. To the extent any requirement of this subpart is inconsistent with the requirements of subparts A or B of this part, the requirements of this subpart will apply.
(a) The pollutants regulated by this subpart are greenhouse gases. The emission guidelines for greenhouse gases established in this subpart are expressed as carbon dioxide (CO
(b) PSD and Title V Thresholds for Greenhouse Gases.
(1) For the purposes of § 51.166(b)(49)(ii), with respect to GHG emissions from facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 51.166(b)(48) and in any State Implementation Plan (SIP) approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48) of this chapter.
(2) For the purposes of § 52.21(b)(50)(ii), with respect to GHG emissions from facilities regulated in the plan, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter.
(3) For the purposes of § 70.2 of this chapter, with respect to greenhouse gas emissions from facilities regulated in the plan, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in § 70.2 of this chapter.
(4) For the purposes of § 71.2, with respect to greenhouse gas emissions from facilities regulated in the plan, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in § 71.2 of this chapter.
If you are the Governor of a State in the contiguous United States with one or more affected EGUs that commenced construction on or before January 8, 2014, you must submit a State or multi-State plan to the U.S. Environmental Protection Agency (EPA) that implements the emission guidelines contained in this subpart. If you are the Governor of a State in the contiguous United States with no affected EGUs for which construction commenced on or before January 8, 2014, in your State, you must submit a negative declaration letter in place of the State plan.
The EPA will review your plan according to § 60.27 except that under § 60.27(b) the Administrator will have 12 months after the date the final plan or plan revision (as allowed under § 60.5785) is submitted, to approve or disapprove such plan or revision or each portion thereof. If you submit an initial submittal under § 60.5765(a) in lieu of a final plan submittal the EPA will follow the procedure in § 60.5765(b).
(a) If you do not submit an approvable plan the EPA will develop a Federal plan for your State according to § 60.27. The Federal plan will implement the emission guidelines contained in this subpart. Owners and operators of affected EGUs not covered by an approved plan must comply with a Federal plan implemented by the EPA for the State.
(b) After a Federal plan has been implemented in your State, it will be withdrawn when your State submits, and the EPA approves, a final plan.
A State may meet its CAA section 111(d) obligations only by submitting a final State or multi-State plan submittal or a negative declaration letter (if applicable).
No. The EPA has no formal review process for negative declaration letters. Once your negative declaration letter has been received, the EPA will place a copy in the public docket and publish a notice in the
The authorities that will not be delegated to State, local, or tribal agencies are specified in paragraphs (a) and (b) of this section.
(a) Approval of alternatives, not already approved by this subpart, to the CO
(b) Approval of alternatives, not already approved by this subpart, to the CO
No. The EPA will not withhold any existing federal funds from a State on account of a State's failure to submit, implement, or enforce an approvable plan or plan revision, or to meet any other requirements under this subpart or subpart B of this part.
(a) This subpart establishes the Clean Energy Incentive Program (CEIP). Participation in this program is optional. The program enables States to award early action emission rate credits (ERCs) and allowances to eligible renewable energy (RE) or demand-side energy efficiency (EE) projects that generate megawatt hours (MWh) or reduce end-use energy demand during 2020 and/or 2021. Eligible projects are those that:
(1) Are located in or benefit a state that has submitted a final state plan that includes requirements establishing its participation in the CEIP; and
(2) Commence construction in the case of RE, or commence operation in the case of demand-side EE, following the submission of a final state plan to the EPA, or after September 6, 2018 for a state that chooses not to submit a final state plan by that date; and either
(3) Generate metered MWh from any type of wind or solar resources; or
(4) Result in quantified and verified electricity savings (MWh) through demand-side EE implemented in low-income communities.
(b) The EPA will award matching ERCs or allowances to States that award early action ERCs or allowances, up to a match limit equivalent to 300 million tons of CO
(1) For RE projects that generate metered MWh from wind or solar resources: For every two MWh generated, the project will receive one early action ERC (or the equivalent number of allowances) from the State, and the EPA will provide one matching ERC (or the equivalent number of allowances) to the State to award to the project.
(2) For EE projects implemented in low-income communities: For every two MWh in end-use demand savings achieved, the project will receive two early action ERCs (or the equivalent number of allowances) from the State, and the EPA will provide two matching ERCs (or the equivalent number of allowances) to the State to award to the project.
(c) You may participate in this program by including in your State plan a mechanism that enables issuance of early action ERCs or allowances by the State to parties effectuating reductions in the calendar years 2020 and/or 2021 in a manner that would have no impact on the emission performance of affected EGUs required to meet rate-based or mass-based emission standards during the performance periods. This mechanism is not required to account for matching ERCs or allowances that may be issued to the State by the EPA.
(d) If you are submitting an initial submittal by September 6, 2016, and you intend to participate in the CEIP, you must include a non-binding statement of intent to participate in the program. If you are submitting a final plan by September 6, 2016, and you intend to participate in the CEIP, your State plan must either include requirements establishing the necessary infrastructure to implement such a program and authorizing your affected EGUs to use early action allowances or ERCs as appropriate, or you must include a non-binding statement of intent as part of your supporting documentation and revise your plan to include the appropriate requirements at a later date.
(e) If you intend to participate in the CEIP, your final State plan, or plan revision if applicable, must require that projects eligible under this program be evaluated, monitored, and verified, and that resulting ERCs or allowances be issued, per applicable requirements of the State plan approved by the EPA as meeting § 60.5805 through § 60.5835.
(a) You must include the components described in paragraphs (a)(1) through (5) of this section in your plan submittal. The final plan must meet the requirements and include the information required under § 60.5745.
(1)
(2)
(i) Your plan does not need to include corrective measures specified in paragraph (a)(2)(ii) of this section if your plan:
(A) Imposes emission standards on all affected EGUs that, assuming full compliance by all affected EGUs, mathematically assure achievement of the CO
(B) Imposes emission standards on all affected EGUS that, assuming full compliance by all affected EGUs, mathematically assure achievement of the CO
(C) Imposes emission standards on all affected EGUs that, assuming full compliance by all affected EGUs, in conjunction with applicable requirements under state law for EGUs subject to subpart TTTT of this subpart, assuming the applicable requirements under state law are met by all EGUs subject to subpart TTTT of this subpart, achieve the applicable mass-based CO
(ii) If your plan does not meet the requirements of (a)(2)(i) or (iii) of this section, your plan must include the requirement for corrective measures to be implemented if triggered. Upon triggering corrective measures, if you do not already have them included in your approved State plan, you must submit corrective measures to EPA for approval as a plan revision per the requirements of § 60.5785(c). These corrective measures must ensure that the interim period and final period CO
(A) Your plan must include a trigger for an exceedance of an interim step 1 or interim step 2 CO
(B) Your plan must include a trigger for an exceedance of an interim step 1 goal or interim step 2 goal of 10 percent or greater based on either reported CO
(C) Your plan must include a trigger for a failure to meet an interim period goal based on reported CO
(D) Your plan must include a trigger for a failure to meet the interim period or any final reporting period CO
(E) Your plan must include a trigger for a failure to meet any final reporting period goal based on reported CO
(F) Your plan must include a trigger for a failure to meet the interim period CO
(G) Your plan must include a trigger for a failure to meet any final reporting period CO
(H) A net allowance import adjustment represents the CO
(iii) If your plan relies upon State measures, in addition to or in lieu of emission standards on your affected EGUs, then the final State plan must include the requirements in paragraph (a)(3) of this section and the submittal must include the information listed in § 60.5745(a)(6).
(iv) If your plan requires emission standards in addition to relying upon State measures, then you must demonstrate that the emission standards and State measures, when taken together, result in the achievement of the applicable mass-based CO
(3)
(i) You must include a trigger for the backstop to go into effect upon:
(A) A failure to meet a programmatic milestone;
(B) An exceedance of 10 percent or greater of an interim step 1 goal or interim step 2 goal based on reported CO
(C) A failure to meet the interim period goal based on reported CO
(D) A failure to meet any final reporting period goal based on reported CO
(ii) You may include in your plan any additional triggers so long as they do not reduce the stringency of the triggers required under paragraph (a)(3)(i) of this section.
(iii) You must include a schedule for implementation of the backstop once triggered, and you must identify all necessary State administrative and technical procedures for implementing the backstop.
(4)
(5)
(i) You must include in your plan a requirement for a report to be submitted by July 1, 2021, that demonstrates that the State has met, or is on track to meet, the programmatic milestone steps indicated in the timeline required in § 60.5770.
(b) You must follow the requirements of subpart B of this part and demonstrate that they were met in your State plan. However, the provisions of § 60.24(f) shall not apply.
(a) In addition to the components of the plan listed in § 60.5740, a final plan submittal to the EPA must include the information in paragraphs (a)(1) through (13) of this section. This information must be submitted to the EPA as part of your final plan submittal but will not be codified as part of the federally enforceable plan upon approval by EPA.
(1) You must include a description of your plan approach and the geographic scope of the plan (
(2) You must identify CO
(i) You must specify in the plan submittal the CO
(ii) [Reserved]
(3) You must include a demonstration that the affected EGUs covered by the plan are projected to achieve the CO
(4) You must include a demonstration that each affected EGU's emission standard is quantifiable, non-
(5) If your plan includes emission standards on your affected EGUs sufficient to meet either the CO
(i) If your plan applies separate rate-based CO
(ii) If a plan applies rate-based emission standards to individual affected EGUs at a lbs CO
(A) An analysis of the change in generation of affected EGUs given the compliance costs and incentives under the application of different emission rate standards across affected EGUs in a State;
(B) A projection showing how generation is expected to shift between affected EGUs and across affected EGUs and non-affected EGUs over time;
(C) Assumptions regarding the availability and anticipated use of the MWh of electricity generation or electricity savings from eligible resources that can be issued ERCs;
(D) The specific calculation (or assumption) of how eligible resource MWh of electricity generation or savings are being used in the projection to adjust the reported CO
(E) If a state plan provides for the ability of renewable energy resources located in states with mass-based plans to be issued ERCs, consideration in the projection that such resources must meet geographic eligibility requirements, consistent with § 60.5800(a); and
(F) Any other applicable assumptions used in the projection.
(iii) If a plan establishes mass-based emission standards for affected EGUs that cumulatively do not exceed the State's EPA-specified mass CO
(iv) If a plan applies mass-based emission standards to individual affected EGUs that cumulatively exceed the State's EPA-specified mass CO
(v) Your plan demonstration to be included in your plan submittal, if applicable, must include the information listed in paragraphs (a)(5)(v)(A) through (L) of this section.
(A) A summary of each affected EGU's anticipated future operation characteristics, including:
(
(
(
(
(
(
(B) An identification of any planned new electric generating capacity.
(C) Analytic treatment of the potential for building unplanned new electric generating capacity.
(D) A timeline for implementation of EGU-specific actions (if applicable).
(E) All wholesale electricity prices.
(F) A geographic representation appropriate for capturing impacts and/or changes in the electric system.
(G) A time period of analysis, which must extend through at least 2031.
(H) An anticipated electricity demand forecast (MWh load and MW peak demand) at the State and regional level, including the source and basis for these estimates, and, if appropriate, justification and documentation of underlying assumptions that inform the development of the demand forecast (
(I) A demonstration that each emission standard included in your plan meets the requirements of § 60.5775.
(J) Any ERC or emission allowance prices, when applicable.
(K) An identification of planning reserve margins.
(L) Any other applicable assumptions used in the projection.
(6) If your plan relies upon State measures, in addition to or in lieu of the emission standards required by paragraph § 60.5740(a)(2), the final State plan submittal must include the information under paragraphs (a)(5)(v) and (a)(6)(i) through (v) of this section.
(i) You must include a description of all the State measures the State will rely upon to achieve the applicable CO
(ii) You must include the schedule and milestones for the implementation of the State measures. If the State measures in your plan submittal rely upon measures that do not have a direct effect on the CO
(iii) You must demonstrate that federally enforceable emission standards for affected EGUs in conjunction with any State measures relied upon for your plan, are sufficient to achieve the mass-based CO
(iv) You must include a CO
(A) A baseline demand and supply forecast as well as the underlying assumptions and data sources of each forecast;
(B) The magnitude of energy and emission impacts from all measures included in the plan and applicable assumptions;
(C) An identification of State-enforceable measures with electricity savings and RE generation, in MWh, expected for individual and collective measures and any assumptions related to the quantification of the MWh, as applicable.
(7) Your plan submittal must include a demonstration that the reliability of the electrical grid has been considered in the development of your plan.
(8) Your plan submittal must include a timeline with all the programmatic milestone steps the State intends to take between the time of the State plan submittal and January 1, 2022 to ensure the plan is effective as of January 1, 2022.
(9) Your plan submittal must adequately demonstrate that your State has the legal authority (
(10) Your State plan submittal must demonstrate that each interim step goal required under § 60.5855(c), will be met and include in its supporting documentation, if applicable, a description of the analytic process, tools, methods, and assumptions used to make this demonstration.
(11) Your plan submittal must include certification that a hearing required under § 60.23(c)(1) on the State plan was held, a list of witnesses and their organizational affiliations, if any, appearing at the hearing, and a brief written summary of each presentation or written submission, pursuant to the requirements of § 60.23(d) and (f).
(12) Your plan submittal must include documentation of any conducted community outreach and community involvement, including engagement with vulnerable communities.
(13) Your plan submittal must include supporting material for your plan including:
(i) Materials demonstrating the State's legal authority and funding to implement and enforce each component of its plan, including emissions standards and/or State measures that the plan relies upon;
(ii) Materials supporting that the CO
(iii) Materials supporting any calculations for CO
(iv) Any other materials necessary to support evaluation of the plan by the EPA.
(b) You must submit your final plan to the EPA electronically according to § 60.5875.
A multi-State plan must include all the required elements for a plan specified in § 60.5740(a). A multi-State plan must meet the requirements of paragraphs (a) and (b) of this section.
(a) The multi-State plan must demonstrate that all affected EGUs in all participating States will meet the CO
(1) For States electing to demonstrate performance with a CO
(2) For States electing to demonstrate performance with a CO
(b) Options for submitting a multi-State plan include the following:
(1) States participating in a multi-State plan may submit one multi-State plan submittal on behalf of all participating States. The joint submittal must be signed electronically, according to § 60.5875, by authorized officials for each of the States participating in the multi-State plan. In this instance, the joint submittal will have the same legal effect as an individual submittal for each participating State. The joint submittal must address plan components that apply jointly for all participating States and components that apply for each individual State in the multi-State plan, including necessary State legal authority to implement the plan, such as State regulations and statutes.
(2) States participating in a multi-State plan may submit a single plan submittal, signed by authorized officials from each participating State, which addresses common plan elements. Each participating State must, in addition, provide individual plan submittals that address State-specific elements of the multi-State plan.
(3) States participating in a multi-State plan may separately make individual submittals that address all elements of the multi-State plan. The plan submittals must be materially consistent for all common plan elements that apply to all participating States, and also must address individual State-specific aspects of the multi-State plan. Each individual State plan submittal must address all required plan components in § 60.5740.
(c) A State may elect to participate in more than one multi-State plan. If your State elects to participate in more than one multi-State plan then you must identify in the State plan submittal required under § 60.5745, the subset of affected EGUs that are subject to the specific multi-State plan or your State's individual plan. An affected EGU can only be subject to one plan.
(d) A State may elect to allow its affected EGUs to interact with affected EGUs in other States through mass-based trading programs or a rate-based trading program without entering into a formal multi-State plan allowed for under this section, so long as such programs are part of an EPA-approved state plan and meet the requirements of paragraphs (d)(1) and (2) of this section, as applicable.
(1) For States that elect to do mass-based trading under this option the State must indicate in its plan that its emission budget trading program will be administered using an EPA-approved (or EPA-administered) emission and allowance tracking system.
(2) For States that elect to use a rate-based trading program which allows the affected EGUs to use ERCs from other State rate-based trading programs, the plan must require affected EGUs within their State to comply with emission standards equal to the sub-category CO
(a) You must submit a final plan with the information required under § 60.5745 by September 6, 2016, unless you are submitting an initial submittal,
(b) For States seeking a two year extension for a final plan submittal, you must include the information in § 60.5765(a) in an initial submittal by September 6, 2016, to receive an extension to submit your final State plan submittal by September 6, 2018.
(c) You must submit all information required under paragraphs (a) and (b) of this section according to the electronic reporting requirements in § 60.5875.
(a) You must sufficiently demonstrate that your State is able to undertake steps and processes necessary to timely submit a final plan by the extended date of September 6, 2018, by addressing the following required components in an initial submittal by September 6, 2016, if requesting an extension for a final plan submittal:
(1) An identification of final plan approach or approaches under consideration and a description of progress made to date on the final plan components;
(2) An appropriate explanation of why the State requires additional time to submit a final plan by September 6, 2018; and
(3) A demonstration or description of the opportunity for public comment on the initial submittal and meaningful engagement with stakeholders, including vulnerable communities, during the time in preparation of the initial submittal and the plans for engagement during development of the final plan.
(b) You must submit an initial submittal allowed in paragraph (a) of this section, information required under paragraph (c) of this section (only if a State elects to submit an initial submittal to request an extension for a final plan submittal), and a final State plan submittal according to § 60.5870. If a State submits an initial submittal, an extension for a final State plan submittal is considered granted and a final State plan submittal is due according to § 60.5760(b) unless a State is notified within 90 days of the EPA receiving the initial submittal that the EPA finds the initial submittal does not meet the requirements listed in paragraph (a) of this section. If the EPA notifies the State that the initial submittal does not meet such requirements, the EPA will also notify the State that it has failed to submit the final plan required by September 6, 2016.
(c) If an extension for submission of a final plan has been granted, you must submit a progress report by September 6, 2017. The 2017 report must include the following:
(1) A summary of the status of each component of the final plan, including an update from the 2016 initial submittal and a list of which final plan components are not complete.
(2) A commitment to a plan approach (
(3) An updated comprehensive roadmap with a schedule and milestones for completing the final plan, including any updates to community engagement undertaken and planned.
(a) The affected EGUs covered by your plan must meet the CO
(b) Your plan must require your affected EGUs to achieve each CO
(1) The interim period.
(2) Each interim step.
(3) Each final reporting period.
(c) The emission standards for affected EGUs regulated under the plan must include the following compliance periods:
(1) For the interim period, affected EGUs must have emission standards that have compliance periods that are no longer than each interim step and are imposed for the entirety of the interim step either alone or in combination.
(2) For the final period, affected EGUs must have emission standards that have compliance periods that are no longer than each final reporting period and are imposed for the entirety of the final reporting period either alone or in combination.
(3) Compliance periods for each interim step and each final reporting period may take forms shorter than specified in this regulation, provided the schedules of compliance collectively end on the same schedule as each interim step and final reporting period.
(d) If your plan relies upon State measures in lieu of or in addition to emission standards for affected EGUs regulated under the plan, then the performance periods must be identical to the compliance periods for affected EGUs listed in paragraphs (c)(1) through (3) of this section.
(a) Emission standard(s) for affected EGUs included under your plan must be demonstrated to be quantifiable, verifiable, non-duplicative, permanent, and enforceable with respect to each affected EGU. The plan submittal must include the methods by which each emission standard meets each of the following requirements in paragraphs (b) through (f) of this section.
(b) An affected EGU's emission standard is quantifiable if it can be reliably measured in a manner that can be replicated.
(c) An affected EGU's emission standard is verifiable if adequate monitoring, recordkeeping and reporting requirements are in place to enable the State and the Administrator to independently evaluate, measure, and verify compliance with the emission standard.
(d) An affected EGU's emission standard is non-duplicative with respect to a State plan if it is not already incorporated as an emission standard in another State plan unless incorporated in multi-State plan.
(e) An affected EGU's emission standard is permanent if the emission standard must be met for each compliance period, unless it is replaced by another emission standard in an approved plan revision, or the State demonstrates in an approvable plan revision that the emission reductions from the emission standard are no longer necessary for the State to meet its State level of performance.
(f) An affected EGU's emission standard is enforceable if:
(1) A technically accurate limitation or requirement and the time period for the limitation or requirement are specified;
(2) Compliance requirements are clearly defined;
(3) The affected EGUs responsible for compliance and liable for violations can be identified;
(4) Each compliance activity or measure is enforceable as a practical matter; and
(5) The Administrator, the State, and third parties maintain the ability to enforce against violations (including if an affected EGU does not meet its emission standard based on its
You may rely upon State measures in support of your plan that are not emission standard(s) on affected EGUs, provided those State measures meet the requirements in paragraph (a) of this section.
(a) Each State measure is quantifiable, verifiable, non-duplicative, permanent, and enforceable with respect to each affected entity (
(1) A State measure is quantifiable with respect to an affected entity if it can be reliably measured in a manner that can be replicated.
(2) A State measure is verifiable with respect to an affected entity if adequate monitoring, recordkeeping and reporting requirements are in place to enable the State to independently evaluate, measure, and verify compliance with the State measure.
(3) A State measure is non-duplicative with respect to an affected entity if it is not already incorporated as a State measure or an emission standard in another State plan or State plan supporting material unless incorporated in a multi-State plan.
(4) A State measure is permanent with respect to an affected entity if the State measure must be met for at least each compliance period, or unless either it is replaced by another State measure in an approved plan revision, or the State demonstrates in an approved plan revision that the emission reductions from the State measure are no longer necessary for the State's affected EGUs to meet their mass-based CO
(5) A State measure is enforceable against an affected entity if:
(i) A technically accurate limitation or requirement and the time period for the limitation or requirement are specified;
(ii) Compliance requirements are clearly defined;
(iii) The affected entities responsible for compliance and liable for violations can be identified;
(iv) Each compliance activity or measure is enforceable as a practical matter; and
(v) The State maintains the ability to enforce violations and secure appropriate corrective actions.
(b) [Reserved]
(a) EPA-approved plans can be revised only with approval by the Administrator. The Administrator will approve a plan revision if it is satisfactory with respect to the applicable requirements of this subpart and any applicable requirements of subpart B of this part, including the requirement in § 60.5745(a)(3) to demonstrate achievement of the CO
(b) You may submit revisions to a plan to adjust CO
(c) If your State is required to submit a notification according to § 60.5870(d) indicating a triggering of corrective measures as described in § 60.5740(a)(2)(i) and your plan does not already include corrective measures to be implemented if triggered, you must revise your State plan to include corrective measures to be implemented. The corrective measures must ensure achievement of the CO
(d) If your plan relies upon State measures, your backstop is triggered under § 60.5740(a)(3)(i), and your State measures plan backstop does not include a mechanism to make up the shortfall, you must revise your backstop emission standards to make up the shortfall. The shortfall must be made up as expeditiously as practicable.
(e) Reliability Safety Valve:
(1) In order to trigger a reliability safety valve, you must notify the EPA within 48 hours of an unforeseen, emergency situation that threatens reliability, such that your State will need a short-term modification of emission standards under a State plan for a specified affected EGU or EGUs. The EPA will consider the notification in § 60.5870(g)(1) to be an approved short-term modification to the State plan without needing to go through the full State plan revision process if the State provides a second notification to the EPA within seven days of the first notification. The short-term modification under a reliability safety valve allows modification to emission standards under the State plan for an affected EGU or EGUs for an initial period of up to 90 days. During that period of time, the affected EGU or EGUs will need to comply with the modified emission standards identified in the initial notification required under § 60.5870(g)(1) or amended in the second notification required under § 60.5870(g)(2). For the duration of the up to 90-day short-term modification, the CO
(2) Plan revisions submitted pursuant to § 60.5870(g)(3) must meet the requirements for State plan revisions under § 60.5785(a).
(a) To meet your plan obligations, you must demonstrate that your affected EGUs are complying with their emission standards as specified in § 60.5740, and you must demonstrate that the emission standards on affected EGUs, alone or in conjunction with any State measures, are resulting in achievement of the CO
(b) If you submit a plan that sets a mass-based emission trading program for your affected EGUs, the State plan must include emission standards and requirements that specify the allowance system, related compliance requirements and mechanisms, and the emission budget as appropriate. These requirements must include those listed in paragraphs (b)(1) through (5) of this section.
(1) CO
(2) Requirements for State allocation of allowances consistent with § 60.5815.
(3) Requirements for tracking of allowances, from issuance through submission for compliance, consistent with § 60.5820.
(4) The process for affected EGUs to demonstrate compliance (allowance “true-up” with reported CO
(5) Requirements that address potential increased CO
(i) You may include, as part of your plan's supporting documentation, requirements enforceable as a matter of State law regulating CO
(ii) You may include requirements in your State plan for emission budget allowance allocation methods that align incentives to generate to affected EGUs or EGUs covered by subpart TTTT of this part that result in the affected EGUs meeting the mass-based CO
(iii) You may submit for the EPA's approval, an equivalent method which requires affected EGUs to meet the mass-based CO
(c) If you submit a plan that sets rate-based emission standards on your affected EGUs, to meet the requirements of § 60.5775, you must follow the requirements in paragraphs (c)(1) through (4) of this section.
(1) You must require the owner or operator of each affected EGU covered by your plan to calculate an adjusted CO
(2) Your plan must specify that an ERC qualifies for the compliance demonstration specified in paragraph (c)(1) of this section if the ERC meets the requirements of paragraphs (c)(2)(i) through (iv) of this section.
(i) An ERC must have a unique serial number.
(ii) An ERC must represent one MWh of actual energy generated or saved with zero associated CO
(iii) An ERC must only be issued to an eligible resource that meets the requirements of § 60.5800 or to an affected EGU that meets the requirements of § 60.5795 and must only be issued by a State or its State agent through an EPA-approved ERC tracking system that meets the requirements of § 60.5810, or by the EPA through an EPA-administered tracking system.
(iv) An ERC must be surrendered and retired only once for purpose of compliance with this regulation through an EPA-approved ERC tracking system that meets the requirements of § 60.5810, or by the EPA through an EPA-administered tracking system.
(3) Your plan must specify that an ERC does not qualify for the compliance demonstration specified in paragraph (c)(1) of this section if it does not meet the requirements of paragraph (c)(2) of this section or if any State has used that same ERC for purposes of demonstrating achievement of a CO
(4) Your plan must include provisions either allowing for or restricting banking of ERCs between compliance periods for affected EGUs, and provisions not allowing any borrowing of any ERCs from future compliance periods by affected EGUs or eligible resources.
(a) For issuance of ERCs to the affected EGUs that generate them, the plan must specify the accounting method and process for ERC issuance. For plans that require that affected EGUs meet a rate-based CO
(1) You must include the calculation method for determining the number of ERCs, denominated in MWh, that may be generated by and issued to an affected EGU that is in compliance with its emission standard, based on the difference between its emission standard and its reported CO
(2) You must include the calculation method for determining the number of ERCs, denominated in MWh, that may be issued to affected EGUs that meet the definition of a stationary combustion turbine based on the displaced emissions from affected EGUs not meeting the definition of a stationary combustion turbine, resulting from the difference between its annualized net energy output in MWh for the calendar year(s) in the compliance period and its net energy output in MWh for the 2012 calendar year (January 1, 2012, through December 31, 2012).
(b) Any ERCs generated through the method described as required by paragraph (a)(2) of this section must not be used by any affected EGUs other than steam generating units or IGCCs to demonstrate compliance as prescribed under § 60.5790(c)(1).
(c) Any states in a multi-State plan that requires the use of ERCs for affected EGUs to comply with their emission standards must have functionally equivalent requirements pursuant to paragraphs (a)(1) and (2) of this section for generating ERCs.
(a) ERCs may only be issued for generation or savings produced on or after January 1, 2022, to a resource that qualifies as an eligible resource because it meets each of the requirements in paragraphs (a)(1) through (4) of this section.
(1) Resources qualifying for eligibility only include resources that increased installed electrical generation nameplate capacity, or implemented new electrical savings measures, on or after January 1, 2013. If a resource had a nameplate capacity uprate, ERCs may be issued only for the difference in generation between its uprated nameplate capacity and its nameplate capacity prior to the uprate. ERCs must not be issued for generation for an uprate that followed a derate that occurred on or after January 1, 2013. A resource that is relicensed or receives a license extension is considered existing capacity and is not an eligible resource, unless it receives a capacity uprate as a result of the relicensing process that is reflected in its relicensed permit. In such a case, only the difference in nameplate capacity between its relicensed permit and its prior permit is eligible to be issued ERCs.
(2) The resource must be connected to, and deliver energy to or save electricity on, the electric grid in the contiguous United States.
(3) The resource must be located in either:
(i) A State whose affected EGUs are subject to rate-based emission standards pursuant to this regulation; or
(ii) A State with a mass-based CO
(4) The resource falls into one of the following categories of resources:
(i) Renewable electric generating technologies using one of the following renewable energy resources: Wind, solar, geothermal, hydro, wave, tidal;
(ii) Qualified biomass;
(iii) Waste-to-energy (biogenic portion only);
(iv) Nuclear power;
(v) A non-affected combined heat and power (CHP) unit, including waste heat power;
(vi) A demand-side EE or demand-side management measure that saves electricity and is calculated on the basis of quantified ex post savings, not “projected” or “claimed” savings; or
(vii) A category identified in a State plan and approved by the EPA to generate ERCs.
(b) Any resource that does not meet the requirements of this subpart or an approved State plan cannot be issued ERCs for use by an affected EGU with its compliance demonstration required under § 60.5790(c).
(c) ERCs may not be issued to or for any of the following:
(1) New, modified, or reconstructed EGUs that are subject to subpart TTTT of this part, except CHP units that meet the requirements of a CHP unit under paragraph (a);
(2) EGUs that do not meet the applicability requirements of §§ 60.5845 and 60.5850, except CHP units that meet the requirements of a CHP unit under paragraph (a);
(3) Measures that reduce CO
(4) Any measure not approved by the EPA for issuance of ERCs in connection with a specific State plan.
(d) You must include the appropriate requirements in paragraphs (d)(1) through (3) of this section for an applicable eligible resource in your plan.
(1) If qualified biomass is an eligible resource, the plan must include a description of why the proposed feedstocks or feedstock categories should qualify as an approach for controlling increases of CO
(2) If waste-to-energy is an eligible resource, the plan must assess both the
(3) If carbon capture and utilization (CCU) is an eligible resource in a plan, the plan must include analysis supporting how the proposed qualifying CCU technology results in CO
(e) States and areas of Indian country that do not have any affected EGUs, and other countries, may provide ERCs to adjust CO
If your plan uses ERCs your plan must include the process and requirements for issuance of ERCs to affected EGUs and eligible resources set forth in paragraphs (a) through (f) of this section.
(a)
(1) Documentation that the eligibility application has only been submitted to you, or pursuant to an EPA-approved multi-State collaborative approach;
(2) An EM&V plan that meets the requirements of the State plan as approved by the EPA as meeting § 60.5830; and
(3) A verification report from an independent verifier that verifies the eligibility of the eligible resource to be issued an ERC and that the EM&V plan meets the requirements of the State plan as approved by the EPA of meeting § 60.5805.
(b)
(c)
(1) An M&V report that meets the requirements of your State plan as approved by the EPA as meeting § 60.5835; and
(2) A verification report from an independent verifier that verifies that the requirements for the M&V report are met.
(e)
(f)
(g)
(h)
(i)
(A) An independent verifier, as defined by this regulation; and
(B) Eligible to verify eligibility applications, EM&V plans, and/or M&V reports per the requirements of the approved State plan as meeting §§ 60.5830 and 60.5835 respectively.
(2)
(a) Your plan must include provisions for an ERC tracking system, if applicable, that meets the following requirements:
(1) It electronically records the issuance of ERCs, transfers of ERCs among accounts, surrender of ERCs by affected EGUs as part of a compliance demonstration, and retirement or cancellation of ERCs; and
(2) It documents and provides electronic, internet-based public access to all information that supports the eligibility of eligible resources and issuance of ERCs and functionality to generate reports based on such information, which must include, for each ERC, an eligibility application, EM&V plan, M&V reports, and independent verifier verification reports.
(b) If approved in a State plan, an ERC tracking system may provide for transfers of ERCs to or from another ERC tracking system approved in a State plan, or provide for transfers of ERCs to or from an EPA-administered ERC tracking system used to administer a Federal plan.
(a) For a mass-based trading program, a State plan must include requirements for CO
(b) Provisions for allocation of allowances for each compliance period prior to the beginning of the compliance period.
(c) Provisions for allocation of set-aside allowance, if applicable, must be established to ensure that the eligible resources must meet the same requirements for the ERC eligible resource requirements of § 60.5800, and the State must include eligibility application and verification provisions equivalent to those for ERCs in § 60.5805 and EM&V plan and M&V report provisions that meet the requirements of § 60.5830 and § 60.5835.
(d) Provisions for adjusting allocations if the affected EGUs or eligible resources are incorrectly allocated CO
(e) Provisions allowing for or restricting banking of allowances between compliance periods for affected EGUs.
(f) Provisions not allowing any borrowing of allowances from future compliance periods by affected EGUs.
(a) Your plan must include provisions for an allowance tracking system, if applicable, that meets the following requirements:
(1) It electronically records the issuance of allowances, transfers of allowances among accounts, surrender of allowances by affected EGUs as part of a compliance demonstration, and retirement of allowances; and
(2) It documents and provides electronic, internet-based public access to all information that supports the eligibility of eligible resources and issuance of set aside allowances, if applicable, and functionality to generate reports based on such information, which must include, for each set aside allowance, an eligibility application, EM&V plan, M&V reports, and independent verifier verification reports.
(b) If approved in a State plan, an allowance tracking system may provide for transfers of allowances to or from another allowance tracking system approved in a State plan, or provide for transfers of allowances to or from an EPA-administered allowance tracking system used to administer a Federal plan.
(a) A plan must require an affected EGU's owners or operators to demonstrate compliance with emission standards in a mass based program by holding an amount of allowances not less than the tons of total CO
(b) In a mass-based trading program a plan may allow multiple affected EGUs co-located at the same facility to demonstrate that they are meeting the applicable emission standards on a facility-wide basis by the owner or operator holding enough allowances to cover the CO
(1) If there are not enough allowances to cover the facility's affected EGUs' CO
(2) [Reserved]
(a) If your plan requires your affected EGUs to meet their emission standards in accordance with § 60.5790, your plan must include requirements that any EM&V plan that is submitted in accordance with the requirements of § 60.5805, in support of the issuance of an ERC or set-aside allowance that can be used in accordance with § 60.5790, must meet the EM&V criteria approved as part of your State plan.
(b) Your plan must require each EM&V plan to include identification of the eligible resource.
(c) Your plan must require that an EM&V plan must contain specific criteria, as applicable to the specific eligible resource.
(1) For RE resources, your plan must include requirements discussing how the generation data will be physically measured on a continuous basis using, for example, a revenue-quality meter.
(2) For demand-side EE, your plan must require that each EM&V plan quantify and verify electricity savings on a retrospective (ex-post) basis using industry best-practice EM&V protocols and methods that yield accurate and reliable measurements of electricity savings. Your plan must also require each EM&V plan to include an assessment of the independent factors that influence the electricity savings, the expected life of the savings (in years), and a baseline that represents what would have happened in the absence of the demand-side EE activity. Additionally, your plan must require that each EM&V plan include a demonstration of how the industry best-practices protocol and methods were applied to the specific activity, project, measure, or program covered in the EM&V plan, and include an explanation of why these protocols or methods were selected. EM&V plans must require eligible resources to demonstrate how all such best-practice approaches will be applied for the purposes of quantifying and verifying MWh results. Subsequent reporting of demand-side EE savings values must demonstrate and explain how the EM&V plan was followed.
(a) If your plan requires your affected EGUs to meet their emission standards in accordance with § 60.5790, your plan must include requirements that any M&V report that is submitted in accordance with the requirements of § 60.5805, in support of the issuance of an ERC or set-aside allocation that can be used in accordance with § 60.5790, must meet the requirements of this section.
(b) Your plan must require that each M&V report include the following:
(1) For the first M&V report submitted, documentation that the energy-generating resources, energy-saving measures, or practices were installed or implemented consistent with the description in the approved eligibility application required in § 60.5805(a).
(2) Each M&V report submitted must include the following:
(i) Identification of the time period covered by the M&V report;
(ii) A description of how relevant quantification methods, protocols, guidelines, and guidance specified in the EM&V plan were applied during the reporting period to generate the quantified MWh of generation or MWh of energy savings;
(iii) Documentation (including data) of the energy generation and/or energy savings from any activity, project, measure, resource, or program addressed in the EM&V plan, quantified and verified in MWh for the period covered by the M&V report, in accordance with its EM&V plan, and based on ex-post energy generation or savings; and
(iv) Documentation of any change in the energy generation or savings capability of the eligible resource from the description of the resource in the approved eligibility application during the period covered by the M&V report and the date on which the change occurred, and/or demonstration that the eligible resource continued to meet the requirements of § 60.5800.
(a) This subpart does not directly affect EGU owners or operators in your State. However, affected EGU owners or operators must comply with the plan that a State or States develop to implement the emission guidelines contained in this subpart.
(b) If a State does not submit a final plan to implement and enforce the emission guidelines contained in this subpart, or an initial submittal for which an extension to submit a final plan can be granted, by September 6, 2016, or the EPA disapproves a final plan, the EPA will implement and enforce a Federal plan, as provided in § 60.5720, applicable to each affected EGU within the State that commenced
(a) The EGUs that must be addressed by your plan are any affected steam generating unit, IGCC, or stationary combustion turbine that commenced construction on or before January 8, 2014.
(b) An affected EGU is a steam generating unit, IGCC, or stationary combustion turbine that meets the relevant applicability conditions specified in paragraph (b)(1) through (3) of this section, as applicable, except as provided in § 60.5850.
(1) Serves a generator or generators connected to a utility power distribution system with a nameplate capacity greater than 25 MW-net (
(2) Has a base load rating (
(3) Stationary combustion turbines that meet the definition of either a combined cycle or combined heat and power combustion turbine.
EGUs that are excluded from being affected EGUs are:
(a) EGUs that are subject to subpart TTTT of this part as a result of commencing construction after the subpart TTTT applicability date;
(b) Steam generating units and IGCCs that are, and always have been, subject to a federally enforceable permit limiting annual net-electric sales to one-third or less of its potential electric output, or 219,000 MWh or less;
(c) Non-fossil units (
(d) Stationary combustion turbines not capable of combusting natural gas (
(e) EGUs that are combined heat and power units that have always historically limited, or are subject to a federally enforceable permit limiting, annual net-electric sales to a utility distribution system to no more than the greater of either 219,000 MWh or the product of the design efficiency and the potential electric output;
(f) EGUs that serve a generator along with other steam generating unit(s), IGCC(s), or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less;
(g) EGUs that are a municipal waste combustor unit that is subject to subpart Eb of this part; and
(h) EGUs that are a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.
(a) You must require, in your plan, emission standards on affected EGUs to meet the CO
(1) You must set CO
(2) [Reserved]
(b) You may elect to require your affected EGUs to meet emission standards that differ from the CO
(1) Average statewide rate-based CO
(2) Cumulative statewide mass-based CO
(c) If your plan meets CO
(1) The interim period and interim steps CO
(2) You must set interim step goals that will either on average or cumulatively meet the State's interim period goal, as applicable to a rate-based or mass-based CO
(d) Your plan's interim period and final period CO
(1) If your plan implements CO
(2) If you elect to require your affected EGUs to meet emission standards to meet mass-based CO
(e) If your plan relies upon State measures in addition to or in lieu of emission standards, you must only use the mass-based goals allowed for in paragraph (b)(2) of this section to demonstrate that your affected EGUs are meeting the required emissions performance.
(f) Nothing in this subpart precludes an affected EGU from complying with its emission standard or you from meeting your obligations under the State plan.
(a) Your plan must include monitoring for affected EGUs that is no less stringent than what is described in (a)(1) through (8) of this section.
(1) The owner or operator of an affected EGU (or group of affected EGUs that share a monitored common stack) that is required to meet rate-based or mass-based emission standards must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter, unless such a plan is already in place under another program that requires CO
(2) For rate-based emission standards, each compliance period shall include
(i) “Valid data” (as defined in § 60.5880) are obtained for all of the parameters used to determine the hourly CO
(ii) The corresponding hourly net energy output value is also valid data (
(3) For rate-based emission standards, the owner or operator of an affected EGU must measure and report the hourly CO
(i) The owner or operator of an affected EGU must install, certify, operate, maintain, and calibrate a CO
(ii) For each “valid operating hour” (as defined in paragraph (a)(2) of this section), calculate the hourly CO
(iii) Next, multiply each hourly CO
(iv) The hourly CO
(v) Sum all of the hourly CO
(vi) For each continuous monitoring system used to determine the CO
(4) The owner or operator of an affected EGU that exclusively combusts liquid fuel and/or gaseous fuel may, as an alternative to complying with paragraph (a)(3) of this section, determine the hourly CO
(i) Implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/hr), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. The fuel flow meter(s) used to measure the hourly fuel flow rates must meet the applicable certification and quality-assurance requirements in sections 2.1.5 and 2.1.6 of appendix D to part 75 (except for qualifying commercial billing meters). The fuel GCV must be determined in accordance with section 2.2 or 2.3 of appendix D, as applicable.
(ii) For each measured hourly heat input rate, use Equation G-4 in Appendix G to part 75 of this chapter to calculate the hourly CO
(iii) For each “valid operating hour” (as defined in paragraph (a)(2) of this section), multiply the hourly tons/hr CO
(iv) The hourly CO
(v) Sum all of the hourly CO
(vi) The owner or operator of an affected EGU may determine site-specific carbon-based F-factors (F
(5) For both rate-based and mass-based standards, the owner or operator of an affected EGU (or group of affected units that share a monitored common stack) must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output. The owner or operator must use the following procedures to calculate net energy output, as appropriate for the type of affected EGU(s).
(i) Determine P
(ii) If there is no net electrical output, but there is mechanical or useful thermal output, either for a particular valid operating hour (for rate-based
(iii) For rate-based applications, if there is no (
(iv) Calculate P
(v) If applicable to your affected EGU (for example, for combined heat and power), you must calculate (Pt)
(vi) For rate-based standards, sum all of the values of P
(vii) For mass-based standards, sum all of the values of P
(6) In accordance with § 60.13(g), if two or more affected EGUs implementing the continuous emissions monitoring provisions in paragraph (a)(2) of this section share a common exhaust gas stack and are subject to the same emissions standard, the owner or operator may monitor the hourly CO
(7) In accordance with § 60.13(g), if the exhaust gases from an affected EGU implementing the continuous emissions monitoring provisions in paragraph (a)(2) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), the hourly CO
(8) Consistent with § 60.5775 or § 60.5780, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly net energy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU. Alternatively, if the EGUs are identical, you may apportion the combined hourly net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU.
(b) For mass-based standards, the owner or operator of an affected EGU must determine the CO
(1) For each operating hour, calculate the hourly CO
(2) Sum all of the hourly CO
(3) The owner or operator of an affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously
(c) Your plan must require the owner or operator of each affected EGU covered by your plan to maintain the records, as described in paragraphs (b)(1) and (2) of this section, for at least 5 years following the date of each compliance period, occurrence, measurement, maintenance, corrective action, report, or record.
(1) The owner or operator of an affected EGU must maintain each record on site for at least 2 years after the date of each compliance period, occurrence, measurement, maintenance, corrective action, report, or record, whichever is latest, according to § 60.7. The owner or operator of an affected EGU may maintain the records off site and electronically for the remaining year(s).
(2) The owner or operator of an affected EGU must keep all of the following records, in a form suitable and readily available for expeditious review:
(i) All documents, data files, and calculations and methods used to demonstrate compliance with an affected EGU's emission standard under § 60.5775.
(ii) Copies of all reports submitted to the State under paragraph (c) of this section.
(iii) Data that are required to be recorded by 40 CFR part 75 subpart F.
(iv) Data with respect to any ERCs generated by the affected EGU or used by the affected EGU in its compliance demonstration including the information in paragraphs (c)(2)(iv)(A) and (B) of this section.
(A) All documents related to any ERCs used in a compliance demonstration, including each eligibility application, EM&V plan, M&V report, and independent verifier verification report associated with the issuance of each specific ERC.
(B) All records and reports relating to the surrender and retirement of ERCs for compliance with this regulation, including the date each individual ERC with a unique serial identification number was surrendered and/or retired.
(d) Your plan must require the owner or operator of an affected EGU covered by your plan to include in a report submitted to you at the end of each compliance period the information in paragraphs (d)(1) through (5) of this section.
(1) Owners or operators of an affected EGU must include in the report all hourly CO
(2) For rate-based standards, each report must include:
(i) The hourly CO
(ii) The net electric output and the net energy output (P
(iii) The calculated CO
(iv) The sum of the hourly net energy output values and the sum of the hourly CO
(v) ERC replacement generation (if any), properly justified (see paragraph (c)(5) of this section); and
(vi) The calculated CO
(3) For mass-based standards, each report must include:
(i) The hourly CO
(ii) The calculated CO
(iii) The sum of the CO
(iv) The net electric output and the net energy output (P
(v) The sum of the hourly net energy output values for all of the unit or stack operating hours in the compliance period.
(vi) Notwithstanding the requirements in paragraphs (c)(3)(i) through (c)(3)(iii) of this section, if the compliance period is a discrete number of calendar years (
(A) The cumulative annual CO
(B) The sum of the cumulative annual CO
(4) For each affected EGU's compliance period, the report must also include the applicable emission standard and demonstration that it met the emission standard. An owner or operator must also include in the report the affected EGU's calculated emission performance as a CO
(5) If the owner or operator of an affected EGU is complying with an emission standard by using ERCs, they must include in the report a list of all unique ERC serial numbers that were retired in the compliance period, and, for each ERC, the date an ERC was surrendered and retired and eligible resource identification information sufficient to demonstrate that it meets the requirements of § 60.5800 and qualifies to be issued ERCs (including location, type of qualifying generation or savings, date commenced generating or saving, and date of generation or savings for which the ERC was issued).
(6) If the owner or operator of an affected EGU is complying with an emission standard by using allowances, they must include in the report a list of all unique allowance serial numbers that were retired in the compliance period, and, for each allowance, the date an allowance was surrendered and retired and if the allowance was a set-aside allowance the eligible resource identification information sufficient to demonstrate that it meets the requirements of § 60.5815(c) and qualifies to be issued set-aside allowances (including location, type of qualifying generation or savings, date commenced generating or saving, and date of generation or savings for which the allowance was issued).
(e) The owner or operator of an affected EGU must follow any additional requirements for monitoring, recordkeeping and reporting in a plan that are required under § 60.5745(a)(4), if applicable.
(f) If an affected EGU captures CO
(1) Report in accordance with the requirements of 40 CFR part 98 subpart RR, if injection occurs on-site;
(2) Transfer the captured CO
(3) Transfer the captured CO
(g) Any person may request the Administrator to issue a waiver of the requirement that captured CO
(a) You must keep records of all information relied upon in support of any demonstration of plan components, plan requirements, supporting documentation, State measures, and the status of meeting the plan requirements defined in the plan for each interim step and the interim period. After 2029, States must keep records of all information relied upon in support of any continued demonstration that the final CO
(b) You must keep records of all data submitted by the owner or operator of each affected EGU that is used to determine compliance with each affected EGU emissions standard or requirements in an approved State plan, consistent with the affected EGU requirements listed in § 60.5860.
(c) If your State has a requirement for all hourly CO
(d) You must keep records at a minimum for 10 years, for the interim period, and 5 years, for the final period, from the date the record is used to determine compliance with an emissions standard, plan requirement, CO
(a) In lieu of the annual report required under § 60.25(e) and (f) of this part, you must report the information in paragraphs (b) through (f) of this section.
(b) You must submit a report covering each interim step within the interim period and each of the final 2-calendar year periods due no later than July 1 of the year following the end of the period. The interim period reporting starts with a report covering interim step 1 due no later than July 1, 2025. The final period reports start with a biennial report covering the first final reporting period (which is due by July 1, 2032), a 2-calendar year average of emissions or cumulative sum of emissions used to determine compliance with the final CO
(1) The report must include the emissions performance achieved by all affected EGUs during the reporting period, consistent with the plan approach according to § 60.5745(a), and identification of whether each affected EGU is in compliance with its emission standard and whether the collective of all affected EGUs covered by the State are on schedule to meet the applicable CO
(2) The report must include a comparison of the CO
(i) For interim step 3, you do not need to include a comparison between the applicable interim step 3 CO
(3) The report must include all other required information, as specified in your State plan according to § 60.5740(a)(5).
(4) If applicable, the report must include a program review that your State has conducted that addresses all aspects of the administration of the State plan and overall program, including State evaluations and regulatory decisions regarding eligibility applications for ERC resources and M&V reports (and associated EM&V activities), and State issuance of ERCs. The program review must assess whether the program is being administered properly in accordance with the approved plan, whether reported annual MWh of generation and savings from qualified ERC resources are being properly quantified, verified, and reported in accordance with approved EM&V plans, and whether appropriate records are being maintained. The program review must also address determination of the eligibility of verifiers by the State and the conduct of independent verifiers, including the quality of verifier reviews.
(c) If your plan relies upon State measures, in lieu of or in addition to emission standards, then you must submit an annual report to the EPA in addition to the reports required under paragraph (b) of this section for the interim period. In the final period, you must submit biennial reports consistent with those required under paragraph (b) of this section. The annual reports in the interim period must be submitted no later than July 1 following the end of each calendar year starting with 2022.
(1) You must include in your report the status of implementation of federally enforceable emission standards (if applicable) and State measures.
(2) You must include information regarding the status of the periodic programmatic milestones to show progress in program implementation. The programmatic milestones with specific dates for achievement must be consistent with the State measures included in the State plan submittal.
(d) If your plan includes the requirement for emission standards on your affected EGUs, then you must submit a notification, if applicable, in the report required under paragraph (b) of this section to the EPA if your affected EGUs trigger corrective measures as described in § 60.5740(a)(2)(i). If corrective measures are required and were not previously submitted with your state plan, you must follow the requirements in § 60.5785 for revising your plan to implement the corrective measures.
(e) If your plan relies upon State measures, in lieu of or in addition to emission standards, than you must submit a notification as required under paragraphs (e)(1) and (2) of this section.
(1) You must submit a notification in the report required under paragraph (c) of this section to the EPA if at the end of the calendar year your State did not meet a programmatic milestone included in your plan submittal. This notification must detail the implementation of the backstop required in your plan to be fully in place within 18 months of the due date of the report required in paragraph (b) of this section. In addition, the notification must describe the steps taken by the State to inform the affected EGUs in its State that the backstop has been triggered.
(2) You must submit a notification in the report required under paragraph (b) of this section to the EPA if you trigger the backstop as described in § 60.5740(a)(3)(i). This notification must detail the steps that will be taken by you to implement the backstop so that it is fully in place within 18 months of the due date of the report required in paragraph (b) of this section. In addition, the notification must describe the steps taken by the State to inform the affected EGUs that the backstop has been triggered.
(f) You must include in your 2029 report (which is due by July 1, 2030) the calculation of average CO
(g) The notifications listed in paragraphs (g)(1) through (3) of this section are required for the reliability safety valve allowed in § 60.5785(e).
(1) As required under § 60.5785(e), you must submit an initial notification to the appropriate EPA regional office within 48 hours of an unforeseen, emergency situation. The initial notification must:
(i) Include a full description, to the extent that it is known, of the emergency situation that is being addressed;
(ii) Identify the affected EGU or EGUs that are required to run to assure reliability; and
(iii) Specify the modified emission standards at which the identified EGU or EGUs will operate.
(2) Within 7 days of the initial notification in § 60.5870(g)(1), the State must submit a second notification to the appropriate EPA regional office that documents the initial notification. If the State fails to submit this documentation on a timely basis, the EPA will notify the State, which must then notify the affected EGU(s) that they must operate or resume operations under the original approved State plan emission standards. This notification must include the following:
(i) A full description of the reliability concern and why an unforeseen, emergency situation that threatens reliability requires the affected EGU or EGUs to operate under modified emission standards from those originally required in the State plan including discussion of why the flexibilities provided under the state's plan are insufficient to address the concern;
(ii) A description of how the State is coordinating or will coordinate with relevant reliability coordinators and planning authorities to alleviate the problem in an expedited manner;
(iii) An indication of the maximum time that the State anticipates the affected EGU or EGUs will need to operate in a manner inconsistent with its or their obligations under the State's approved plan;
(iv) A written concurrence from the relevant reliability coordinator and/or planning authority confirming the existence of the imminent reliability threat and supporting the temporary modification request or an explanation of why this kind of concurrence cannot be provided;
(v) The modified emission standards or levels that the affected EGU or EGU will be operating at for the remainder of the 90-day period if it has changed from the initial notification; and
(vi) Information regarding any system-wide or other analysis of the reliability concern conducted by the relevant planning authority, if any.
(3) At least 7 days before the end of the 90-day reliability safety valve period, the State must notify the appropriate EPA regional office that either:
(i) The reliability concern has been addressed and the affected EGU or EGUs can resume meeting the original emission standards in the State plan approved prior to the short-term modification; or
(ii) There still is a serious, ongoing reliability issue that necessitates the affected EGU or EGUs to emit beyond the amount allowed under the State plan. In this case, the State must provide a notification to the EPA that it will be submitting a State plan revision according to paragraph § 60.5785(a) of this section to address the reliability issue. The notification must provide the date by which a revised State plan will be submitted to EPA and documentation of the ongoing emergency with a written concurrence from the relevant reliability coordinator and/or planning authority confirming the continuing urgent need for the affected EGU or EGUs to operate beyond the requirements of the State plan and that there is no other reasonable way of addressing the ongoing reliability emergency but for the affected EGU or EGUs to operate under an alternative emission standard than originally approved under the State plan. After the initial 90-day period, any excess emissions beyond what is authorized in the original approved State plan will count against the State's overall CO
(a) You must submit to the EPA the information required by these emission guidelines following the procedures in paragraphs (b) through (e) of this section.
(b) All negative declarations, State plan submittals, supporting materials that are part of a State plan submittal, any plan revisions, and all State reports required to be submitted to the EPA by the State plan must be reported through EPA's State Plan Electronic Collection
(c) Only a submittal by the Governor or the Governor's designee by an electronic submission through SPeCS shall be considered an official submittal to the EPA under this subpart. If the Governor wishes to designate another responsible official the authority to submit a State plan, the EPA must be notified via letter from the Governor prior to the September 6, 2016, deadline for plan submittal so that the official will have the ability to submit the initial or final plan submittal in the SPeCS. If the Governor has previously delegated authority to make CAA submittals on the Governor's behalf, a State may submit documentation of the delegation in lieu of a letter from the Governor. The letter or documentation must identify the designee to whom authority is being designated and must include the name and contact information for the designee and also identify the State plan preparers who will need access to SPeCS. A State may also submit the names of the State plan preparers via a separate letter prior to the designation letter from the Governor in order to expedite the State plan administrative process. Required contact information for the designee and preparers includes the person's title, organization and email address.
(d) The submission of the information by the authorized official must be in a non-editable format. In addition to the non-editable version all plan components designated as federally enforceable must also be submitted in an editable version. Following initial plan approval, States must provide the EPA with an editable copy of any submitted revision to existing approved federally enforceable plan components, including State plan backstop measures. The editable copy of any such submitted plan revision must indicate the changes made at the State level, if any, to the existing approved federally enforceable plan components, using a mechanism such as redline/strikethrough. These changes are not part of the State plan until formal approval by EPA.
(e) You must provide the EPA with non-editable and editable copies of any submitted revision to existing approved federally enforceable plan components, including State plan backstop measures. The editable copy of any such submitted plan revision must indicate the changes made at the State level, if any, to the existing approved federally enforceable plan components, using a mechanism such as redline/strikethrough. These changes are not part of the State plan until formal approval by EPA.
As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subparts A, B, and TTTT, of this part.
(1) For an affected EGU, the reported CO
(2) For a State (or states in a multi-state plan) calculating a collective CO
(1) The net electric or mechanical output from the affected facility, plus 100 percent of the useful thermal output measured relative to SATP conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (
(2) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output; (
Environmental Protection Agency (EPA).
Proposed rule.
In this action, the Environmental Protection Agency (EPA) is proposing a federal plan to implement the greenhouse gas (GHG) emission guidelines (EGs) for existing fossil fuel-fired electric generating units (EGUs) under the Clean Air Act (CAA). The EGs were proposed in June 2014 and finalized on August 3, 2015 as the Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (also known as the Clean Power Plan or EGs). This proposal presents two approaches to a federal plan for states and other jurisdictions that do not submit an approvable plan to the EPA: a rate-based emission trading program and a mass-based emission trading program. These proposals also constitute proposed model trading rules that states can adopt or tailor for implementation of the final EGs. The federal plan is an important measure to ensure that congressionally mandated emission standards under the authority of the CAA are implemented. The proposed federal plan is related to but separate from the final EGs. The final EGs establish the best system of emission reduction (BSER) for applicable fossil fuel-fired EGUs in the form of a carbon dioxide (CO
Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2015-0199, to the Federal eRulemaking Portal:
Ms. Toni Jones, Fuels and Incineration Group, Sector Policies and Programs Division (E143-05), Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-0316; fax number: (919) 541-3470; email address:
In the CAA, Congress created a partnership between the EPA and the states. Under section 111(d) of the CAA, the EPA establishes emission performance levels based on its determination of the BSER for existing sources of air pollution and provides guidelines for state plans to apply standards of performance to their sources that meet the BSER level of performance. The EPA promulgated EGs under CAA section 111(d) which set source-level CO
While it has been the EPA's longstanding view that the statute identifies states as the preferred implementers of CAA programs, the agency makes clear in the EGs that states cannot and will not be penalized for failing to participate in this program. However, if a state does not submit an approvable plan under section 111(d) of the CAA, the EPA will develop, implement, and enforce a federal plan to reduce CO
Accordingly, the EPA proposes a federal plan under section 111(d) of the CAA for the control of CO
At the same time, these two proposed options offer states model trading rules that the states can follow in developing their own plans in order to capitalize on the flexibility built into the final EGs. Thus, this document proposes four discrete actions: (1) A rate-based federal plan for each state with affected EGUs; (2) a mass-based federal plan for each state with affected EGUs; (3) a rate-based model trading rule for potential use by any state; and (4) a mass-based model trading rule for potential use by any state. The regulatory text of each federal plan and corresponding model trading rule is identical, except as indicated otherwise within the text of the model rule (for instance, the EPA is providing model rule text for states to use related to the crediting of a broader set of clean energy resources than is being proposed in the federal plan).
The EPA intends to finalize both the rate-based and mass-based model trading rules in summer 2016. The EPA will finalize a federal plan for only a given state in the event that the state does not submit an approvable plan by the deadlines specified in the final EGs and the EPA takes action finding that the state has failed to submit a plan, or disapproving a submitted plan because it does not meet the requirements of the EGs.
It is the EPA's intention to give the states as much opportunity as possible to set their own course for carrying out the EGs. Even where a federal plan is put in place for a particular state, that state will still be able to submit a plan, which, upon approval, will allow the state and its sources to exit the federal plan. In addition, as discussed in section VI.A of this preamble, states may take delegation of administrative aspects of the federal plan in order to become the primary implementers. And as discussed in sections V.E and VII.A of this preamble, states may submit partial state plans in order to take over the implementation of a portion of a federal plan. For instance, in a mass-based trading program, the agency proposes to allow states to submit partial state plans to replace the federal plan allowance-distribution provisions with their own allowance-distribution provisions, similar to the approach we have taken in prior trading programs. Finally, even in states in which the affected EGUs are operating under a federal plan, the agency recognizes that states may adopt complementary measures outside of CAA programming to facilitate compliance and lower costs that could benefit power generators and consumers, directly or indirectly.
A state program that adheres to the model trading rule provisions specified in this rulemaking would be presumptively approvable. States may submit means of meeting the EGs' requirements that differ from the model trading rule provisions, so long as the state demonstrates to the EPA's satisfaction in the state plan submittal that such alternative means of addressing requirements are at least as stringent as the presumptively approvable approach described here.
The agency is proposing a finding that it is necessary or appropriate to implement a CAA section 111(d) federal plan for the affected EGUs located in Indian country. CO
This document also proposes certain enhancements to the process and timing for state submittals and EPA action in the CAA section 111(d) framework regulations of 40 CFR part 60, subpart B (these proposals are not a part of the federal plan or model trading rules). These changes, if finalized, would be applicable under the Clean Power Plan and other CAA section 111(d) rules. These changes clarify the availability of certain procedural mechanisms similar to those available under CAA section 110 (such as calls for plan revisions and the availability of “conditional approvals,” etc.). They also extend the deadlines for EPA action, in part to conform with the timelines in the EGs. These changes do not alter the timelines for state action under the EGs and do not alter the submission requirements established in the EGs. Finally, the agency proposes to clarify and request comment on an interpretive issue raised in the Clean Power Plan proposal regarding whether a reconstruction or modification that is subject to a CAA section 111(b) standard moves an existing source out of a CAA section 111(d) program. These proposed changes are discussed in section VII of this preamble. The agency intends to finalize these changes earlier than the finalization of the model trading rules.
In proposing a federal plan, the EPA considered a variety of potential impacts that its action might have on the environment, on businesses, particularly in the energy sector, and on the reliability of the electrical grid. The agency gave extensive consideration to impacts on vulnerable communities, particularly low-income communities, communities of color, and indigenous communities. These considerations are discussed in sections III, VIII, IX, and X of this preamble.
The agency convened a Small Business Advocacy Review Panel under the Regulatory Flexibility Act and has completed an Initial Regulatory Flexibility Analysis (IRFA). Various recommendations from the Panel are found reflected throughout this proposal. In section X of this preamble, the agency explains how it has conducted or intends to conduct all other statutory or executive order (EO) reviews that apply to this proposed action. The EPA also explains in this document how it proposes to take into consideration the “remaining useful lives” of affected EGUs in the design of the proposed federal plan, as discussed below in section III.G of this preamble.
The agency considered the impacts this action could have on the electricity grid and developed options for compliance that are cost-effective and that provide substantial flexibility for the affected EGUs that will accommodate the parties charged with maintaining the reliability of electrical power. A key feature of the proposed federal plan and model trading rule is that the flexibility inherent in both of the two approaches (
The EPA outlined and initiated the Clean Energy Incentive Program (CEIP) in the final EGs (see section VIII of the final EGs). The program is designed to
We also reviewed impacts that this action could have on the environment and the need to ensure environmental integrity of the program as well as avoid unintended environmental impacts. We took measures to ensure that the reductions in carbon emissions this plan will achieve are real, and not just apparent. As in the EGs, in both the rate- and mass-based approaches, the EPA has incorporated components to address the concern that the dynamics of either a rate- or mass-based trading program could incentivize shifting generation from existing units in ways that would result in more CO
We considered whether compliance choices under a federal plan could lead to an unintended concentration of other air pollutants in certain overburdened communities, particularly low-income communities and communities of color. As discussed below, our analysis shows why we do not expect this to occur at any significant level. In general, as in the EGs, we anticipate that the federal plan will result in overall reductions of co-pollutants, in addition to reductions in CO
In the final EGs, the EPA emphasized the importance of state actions to ensure that in developing their respective compliance plans the states addressed the concerns and priorities of vulnerable communities. In the process of developing a final federal plan, the EPA will take actions to address those concerns as well. In addition to the public hearings that the EPA will be holding for all members of the American public on this proposed rulemaking, we will also be conducting a national webinar and outreach meeting(s) in all ten regions on this proposed rulemaking for communities. The goal of these outreach activities is to provide communities with the information they need to understand how the proposed rulemaking will potentially impact their respective communities. At the same time, this information will be useful in helping communities engage the EPA during our comment period, as well as with their states during the state plan development process. We will also be providing other outreach and support activities for vulnerable communities, which are outlined in the community and environmental justice (EJ) considerations in section IX.B of this preamble.
In this action, the EPA is proposing a federal plan to implement the Clean Power Plan EGs for affected fossil fuel-fired EGUs operating in states that do not have approved state plans. Specifically, the EPA is co-proposing two different approaches to a federal plan to implement the Clean Power Plan EGs—a rate-based trading approach and a mass-based trading approach. While establishing emission standards for affected EGUs that would be directly enforceable against the owners and operators of the source, both approaches would grant EGUs substantial flexibility in meeting their compliance obligations. For this reason, among others, these proposed approaches also serve as two proposed model trading rules that states may adopt or tailor in designing their own plans.
The EGs provide that states have until September 6, 2016 (or upon making an initial submittal, until September 6, 2018) to submit state plans, and the EPA does not intend to finalize and implement the federal plan for any states prior to the agency's action of determining a failure to submit a state plan or disapproving a state plan. At the same time, in order to support states' consideration of adoption of one of the model trading rules as an approvable state plan, the agency intends to finalize either or both model rule options presented in this proposed rule by summer 2016, prior to the deadline for state submittals.
The EPA currently intends to finalize a single approach—
The stringency of the proposed federal plan is the same as the CO
In the first approach, the EPA would implement a rate-based emissions trading program. In a rate-based program, affected EGUs must meet an emission standard, derived from the EGs, expressed as a rate of pounds of CO
The second approach to a federal plan that the EPA is proposing in this action is a mass-based trading program. In a mass-based program, the EPA would create a state emissions budget equal to the total tons of CO
The EPA is proposing in this action a finding that it is necessary or appropriate to regulate affected EGUs in certain parts of Indian country via a federal plan. This is discussed in section VI.D of this preamble.
In this action, the EPA is also proposing a number of changes to the framework CAA section 111(d) regulations of 40 CFR part 60, subpart B. These changes generally are intended to provide enhancements to the process for state plan submissions and the timing of EPA actions related to state plans and the federal plan. Specifically, the EPA proposes six changes, to include: (1) Partial approval/disapproval mechanisms similar to CAA section 110(k)(3); (2) a conditional approval mechanism similar to CAA section 110(k)(4); (3) a mechanism for the EPA to make calls for plan revisions similar to the “SIP-call” provisions of CAA section 110(k)(5); (4) an error correction mechanism similar to CAA section 110(k)(6); (5) completeness criteria and a process for determining completeness of state plans and submittals similar to CAA section 110(k)(1) and (2); and (6) updates to the deadlines for EPA action. These proposed changes are explained in greater detail in section VII of this preamble. They are not a component of the proposed federal plan, or changes in the EGs. If these changes are finalized, they will be applicable to other CAA section 111(d) rules. The EPA intends to finalize these changes earlier than the finalization of the model trading rules.
This table is not intended to be exhaustive, but rather provides a general guide for identifying entities likely to be affected by the proposed action. Whether an affected EGU is affected by this action is described in the applicability criteria in 40 CFR 60.5845 and 60.5850 of subpart UUUU. Questions regarding the applicability of this action to a particular entity should be directed to the person listed in the preceding
For the federal plan, the definition of an affected EGU is identical to the definition in the final Clean Power Plan. Additionally, the applicability of the federal plan is consistent with the EGs, where an affected EGU subject to the federal plan is any steam generating unit (SGU), integrated gasification combined cycle (IGCC), or stationary combustion turbine (SCT) that was in operation or had commenced construction as of January 8, 2014,
Section 111(d) of the CAA, as amended, 42 U.S.C. 7411(d), authorizes the EPA to develop and implement a federal plan for affected EGUs upon the EPA's action finding a failure to submit or disapproving a state plan.
Do not submit information that you consider to be CBI electronically through
If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the
On August 3, 2015, the EPA finalized the Clean Power Plan EGs for existing fossil fuel-fired EGUs (40 CFR part 60, subpart UUUU) under authority of section 111 of the CAA (79 FR 34950). The Guidelines apply to existing fossil fuel-fired EGUs,
The agency believes it is appropriate to propose the federal plan at this time for any states that may ultimately be found to have failed to submit a plan, or had their plan disapproved by the EPA. For some states in this situation, the federal plan may be no more than an interim measure to ensure that congressionally mandated emission standards under authority of section 111 of the CAA are implemented until they can get an approved plan in place. Other states may choose to rely on the federal plan and would not need to develop their own plan. This proposal also serves as two proposed model trading rules which states can adopt or tailor for adoption as their state plan. The role of the model rules is discussed in section II.B of this preamble.
In this proposal, the EPA is soliciting public comment only on the proposed approaches for a federal plan and model trading rule for the implementation of the Clean Power Plan EGs. Comments on the underlying Clean Power Plan rule will be considered outside the scope for this proposed rule.
The purpose of this action is two-fold: (1) To co-propose two approaches to a
Section 111 of the CAA and 40 CFR 60.27 require the EPA to develop, implement and enforce a federal plan to cover existing EGUs located in states that do not have an approved plan. Section 111(d) of the CAA relies upon states as the preferred implementers of EGs for existing EGUs. States with affected EGUs are to submit state plans or make initial submittals to the EPA by September 6, 2016 pursuant to the EGs.
The EPA is also proposing the federal plan approaches as two forms of a model trading rule (mass-based and rate-based), which states can adopt or tailor for implementation as a state plan under the EGs. The EPA intends to finalize the model trading rules earlier than it promulgates a federal plan for a state. When the EPA finalizes one or both of its proposed approaches as a final model trading rule, and a state adopts a final model trading rule in its entirety as its state plan, it would be presumptively approvable.
The EPA has designed these rules so that they meet the requirements of the final EGs. If one of the model rules is adopted by a state without any change, it would be presumptively approvable. We use the term “presumptively” in recognition that a state plan submission must be accompanied by other materials in addition to the regulatory provisions. These requirements are set forth in the final Clean Power Plan and framework regulations of 40 CFR part 60, subpart B. For instance, they include a formal letter of submittal from the Governor or his or her designee, evidence that the rule has been adopted into state law and that the state has necessary legal authority to implement and enforce the rule, and evidence that procedural requirements, including public participation under 40 CFR 60.23, have been met.
In further support of state use of the model rules, we are drafting the model trading rule so that it can be adopted or incorporated by reference with a minimum of changes that would be necessary to make the rule appropriate for use by states. This way, a state may incorporate by reference the model rule as the state plan, or as the backstop to a state measures plan with few if any adjustments. States may make changes to the model trading rule, so long as they still meet the requirements of the EGs. If the state chooses to tailor or modify the model trading rule such as by expanding the scope of eligibility of projects that may generate ERCs in a rate-based trading program, the EPA may still approve the plan, but the EPA would conduct appropriate review of such provisions for consistency with the EGs and the state would have to demonstrate to the EPA's satisfaction that its alternative provisions are as stringent as the presumptively approvable approach described. We note here, and in the regulatory text of the model trading rule, that the scope of eligibility of proposed “ERC resources” for the federal plan is different than the scope of eligibility provided for in the model rule. Thus, all of the language and provisions in the regulatory text relevant to these other ERC resources is relevant only to the proposed model trading rule and not to the federal plan as such (
The EPA's approval of a state plan, including a plan that adopts the model trading rule, will be the result of an independent notice-and-comment rulemaking process. Without prejudging the outcome of that process, the EPA recognizes that it may be able to approve or “conditionally approve” state plans that are substantially similar, but not identical to, the final model trading rules. Ultimately, state plans must meet the requirements of the EGs for approvability. Thus, a conditional approval would be based on a condition that the state take such actions as may be necessary by a date certain to meet the requirements of the EGs. (The EPA is proposing to explicitly provide for conditional approvals in the CAA section 111(d) framework regulations. See section VII.B of this preamble.)
In accordance with the EGs, the process for review and approval (or disapproval) of state plans, whether based on the model trading rules or otherwise, would occur once the states have made their submissions by September 6, 2016. As provided in the EGs, states have the option of not submitting a full state plan, but rather making an initial submittal, in order to obtain an extension of 2 years before submitting a full state plan for EPA approval. It could be beneficial for coordination purposes if a state that is interested in adopting one of the model trading rules but intends to make an initial submittal next year were to indicate which model trading rule they intend to adopt. This is not an additional requirement beyond what the EGs require for initial submittals, however.
The EPA strongly encourages states to consider adopting one of the model trading rules, which are designed to be referenced by states in their rulemakings. Use of the model trading rules by states would help to ensure consistency between and among the state programs, which is useful for the potential operation of a broad trading program that spans multi-state regions or operates on a national scale. As discussed at length in the EGs, EGUs operate less as individual, isolated entities and more as multiple components of a large interconnected system designed to integrate a range of functions that ensure an uninterrupted supply of affordable and reliable electricity while also, for the past several decades, maintaining compliance with air pollution control programs. Since, as a practical matter under both the EGs and any federal plan, emission reductions must occur at the affected EGUs, a broad-scale emissions trading program would be particularly effective in allowing EGUs to operate in a way that achieves pollution control without disturbing the overall system of which they are a part and the critical functions that this system performs. In addition, consistency of requirements benefits the affected EGUs, as well as the states and the EPA in their roles as administrators and implementers of a trading program. States of course remain free to develop a plan of their own choosing to submit to the EPA for approval following the
The EPA believes there are compelling policy reasons that support the provision of a proposed model trading rule at this time. The EPA has heard from multiple stakeholders and in public comments submitted on the proposed EGs that there is a strong interest in seeing a model state plan or trading rule prior to the deadline for state submittals under the EGs. According to these stakeholders, model rules can provide predictability for planning purposes, both among states and affected EGUs. In addition, some states have indicated that they may prefer to rely on a federal plan, either temporarily or permanently, rather than develop a plan of their own. This proposal of a model trading rule addresses these policy interests.
The approach of proposing model trading rules that are identical in all key respects to proposed federal plans that may be promulgated later, is consistent with prior CAA section 111(d) and CAA section 110 rulemakings. For example, the NO
Section 111(d)(2) of the CAA, 42 U.S.C. 7411(d)(2) provides the EPA the same authority to prescribe a plan for a state in cases where the state fails to submit a satisfactory plan as the agency would have under CAA section 110(c) in the case of failure to submit an implementation plan. In addition, the EPA has authority under CAA section 111(d)(1) to prescribe regulations that establish procedures similar to CAA section 110 with respect to the submission of state plans, and the EPA also has general rulemaking authority as necessary to implement the CAA under CAA section 301. A federal plan under CAA section 111(d) applies, implements and enforces standards of performance for affected EGUs. Under the Clean Power Plan EGs, state plans will be due on September 6, 2016, but states are also allowed to seek a 2-year extension for a final plan submittal, upon a satisfactory initial plan submittal by the same deadline.
Further, states will remain free, and indeed are strongly encouraged, to submit an approvable state plan even after promulgation of the federal plan for their jurisdictions. The EPA will withdraw the federal plan for a state when that state submits, and the EPA approves, a final plan.
This action co-proposes two approaches to the federal plan, both of which also constitute proposed model trading rules that states could adopt as state plans for EPA approval. The EPA currently intends to finalize one or both of the model trading rules by next summer so that they may be available to states as soon as possible to help inform their state plan development efforts prior to the initial submittal deadline of September 6, 2016, and 2 years before the states' final plan deadline of September 6, 2018.
In this action, the EPA is also proposing enhancements to the process for agency action on state submittals and promulgation of a federal plan under CAA section 111(d). For more detailed discussion of these changes, see section VII of this preamble. This aspect of this proposal is separate from the federal plan and the model trading rules. The EPA intends to finalize these changes on a timeline earlier than both a model trading rule and the federal plan.
Under the framework regulations as proposed to be amended,
The timeframes stated in the previous paragraph reflect the maximum time allowed for EPA action. We note that under CAA section 111(d)(2) and CAA section 110(c), the EPA may promulgate a final federal plan for a state immediately upon making a finding of failure to submit a state plan or initial submittal, or upon making a finding of final disapproval of a state plan. Congress gave the EPA authority in CAA section 111(d)(2), as it did in CAA section 110(c), to promulgate a federal plan at any time after it disapproves or finds a failure to submit a state plan. The Supreme Court has recognized that under this authority, the EPA may promulgate a FIP “at any time” within the 2-year limit of CAA section 110(c) “that begins the moment EPA determines a SIP to be inadequate.”
It is the agency's intention to promulgate federal plans promptly for states who do not submit plans or initial submittals by September 6, 2016. However, the effect of putting the federal plan in place at that time would ultimately be limited in impact upon states. Because the EPA would implement the federal plan, its promulgation does not obligate state officials to take any actions themselves. Further, states remain free—and the EPA in fact encourages states—to submit state plans that can replace the federal plan. States can do so in advance of the beginning of the performance period in 2022, or may transfer to a state plan after that date. However, in doing so, the agency and states should be mindful of the goals of regulatory certainty discussed in the prior paragraph.
Because we are proposing a federal plan that would apply emission standards to affected EGUs in all states that the agency determines not to have an approvable plan, the EPA invites comment from all persons with concerns about or comments on the proposed federal plan as it may apply in any state, whether or not that state has submitted, or intends to submit, its own plan on which the EPA has yet to take action.
In this document, the EPA is proposing regulatory text setting out the substantive provisions for both of the proposed federal plans/model trading rules. The EPA is not providing specific regulatory text that would, if finalized, actually promulgate a federal plan for each state for which this proposed federal plan might be applied.
As discussed in the final EGs, the EPA believes that either a mass-based or rate-based model trading rule could function well as the federally enforceable “backstop” that the EGs require to be included in “state measures” type state plans.
The EGs explicitly recognized that the backstop emission standards could be based on one of the model trading rules that the EPA is proposing in this action. As discussed in section II.B of this preamble above, we are drafting the model trading rule so that it can be adopted or incorporated by reference with a minimum of changes necessary to make the rule appropriate for use by states, and this includes its use as a backstop. Instances of this approach are throughout the proposed rule text and reflect our desire to ease the use of the model rule for states, as a full state plan, or as a backstop to a “state measures” plan.
One way in which a backstop may need to differ from the model trading rules proposed in this action is the requirement to make up for a shortfall in emissions performance in a state's prior plan performance period. The model trading rules do not provide provisions that would automatically adjust the emission standards to account for any prior emission performance shortfall (which is an option states have if designing their own backstop). Thus, a state relying on the model trading rule as its backstop would likely need to submit an appropriate revision to the backstop emission standards adjusting for the shortfall through the state plan revision process. This would likely be done in conjunction with the process for putting the backstop into effect.
If a state chooses to use the model rule as its federally enforceable backstop in a state measures plan, this does not mean that the backstop is itself the federal plan. Rather, the model rule becomes adopted as a part of the state plan. Both approaches to the model trading rule are “emission standard” approaches under the EGs where an emission standard is imposed and federally enforceable on the affected EGUs: In the rate-based approach the emissions standard is an allowable rate of emissions; in the mass-based approach the emission standard is the requirement to hold allowances equal to reported emissions. The EPA may also handle the administration of the trading program for states utilizing the model trading rule. However, even though the backstop may take the form of an EPA-administered, federally-enforceable trading rule, this does not mean that a federal plan has been put into effect. The state retains all of its rights and responsibilities with respect to the implementation and enforcement of the backstop as a component of its state plan.
The EPA intends to set up and administer a program to track trading programs—both rate-based and mass-based—that will be available for all states that choose it. The EPA proposes that affected EGUs in any state covered by a federal plan could trade compliance instruments with affected EGUs in any other state covered by a federal plan or a state plan meeting the conditions for linkage to the federal plan. In the proposed mass-based federal plan trading program, this would mean that affected EGUs in a state covered by the federal plan or a state meeting the conditions for linkage to the federal plan could use, as a compliance instrument, an allowance distributed in any other state covered by the federal plan or a state meeting the conditions for linkage to the federal plan. Similarly, in the proposed rate-based federal plan trading program approach, this would mean that affected EGUs in a state covered by the federal plan or a state meeting the conditions for linkage to the federal plan could use, as a compliance instrument, an ERC issued in any other state covered by the federal plan or a state meeting the conditions for linkage to the federal plan. We propose that an affected EGU in a state covered by the mass-based trading federal plan must use allowances for compliance (not ERCs). Similarly, an affected EGU in a state covered by the rate-based trading federal plan must use ERCs for compliance (not allowances).
The agency promulgated provisions for “ready-for-interstate-trading” plans in the EGs. The EPA is proposing the federal plans as ready-for-interstate-trading plans. State plans that adopt the model rule are also considered ready-for-interstate-trading. The EPA proposes to allow interstate trading between affected EGUs in states covered by the proposed federal plans and affected EGUs in states covered by state plans (referred to below as “linking” states, or “linkages”) under the following conditions, which are discussed further below the list:
• The state plan must be approved.
• The state plan must implement the same type of trading program as the federal plan trading program in order to
• The state plan must use the identical compliance instrument as the federal plan (this requirement is detailed below).
• The state plan must be approved as a ready-for-interstate-trading plan.
• The state plan must use an EPA-administered tracking system (we are also requesting comment on expanding this to include a state plan that uses an EPA-designated tracking system that is interoperable with an EPA-administered system, as detailed below).
The EPA proposes that interstate ERC trading could occur both (1) from affected EGUs in states covered by the rate-based trading federal plan to affected EGUs in states with approved rate-based trading state plans meeting the proposed conditions for linkages (including the conditions for being “ready-for-interstate-trading” that were finalized in the EG), and (2) from affected EGUs in such state-plan-covered states to affected EGUs in federal-plan-covered states. The EPA also requests comment on expanding the scope of interstate trading to include linking states covered by the rate-based trading federal plan with any state that has an approved rate-based trading state plan meeting the proposed conditions for linkages and that uses an EPA-designated ERC tracking system that is interoperable with an EPA-administered ERC tracking system. The EPA also requests comment on allowing a state that has an approved rate-based trading state plan meeting the proposed conditions for linkages and that uses an EPA-designated ERC tracking system to register with the EPA, and after registration, to link with states covered by the rate-based trading federal plan. There are multiple benefits to a registration requirement, which include ensuring that the tracking systems are functionally interoperable.
For the mass-based federal plan, the EPA proposes that interstate allowance trading could occur in both directions,
The EPA proposes that a condition of linkage between a state plan and the federal plan is the use of an identical compliance instrument. In the mass-based federal plan the EPA proposes to issue allowances in short tons; as a result, the EPA is proposing in this rule that linkage for the mass-based federal plan is limited to state plans that issue allowances in short tons. The agency also requests comment on whether to extend linkage to state plans that issue allowances in metric tons and on what provisions would be necessary to implement such linkages. The EPA believes that considerations for linkages to state plans that use metric tons may include tracking system design, and stipulation of which parties convert state plan allowances denominated in metric tons to allowances denominated in short tons and at what stage of compliance operations the conversion occurs. The agency requests comment on these and any other considerations for linkages between the federal plan and state plans that issue allowances in metric tons.
The EPA also requests comment on expanding the scope of interstate trading to include linking states covered by the mass-based trading federal plan with any state that has an approved mass-based trading state plan meeting the proposed conditions for linkages and that uses an EPA-designated allowance tracking system that is interoperable with an EPA-administered allowance tracking system. The EPA also requests comment on allowing a state that has an approved mass-based trading state plan meeting the proposed conditions for linkages and that uses an EPA-designated allowance tracking system to register with the EPA, and after registration, to link with states covered by the mass-based trading federal plan.
In the Clean Power Plan EGs, the EPA promulgated requirements that apply to an emissions budget trading state plan that includes non-affected EGU emission sources, to provide the opportunity for such a state plan to be potentially approvable for linking to other state plans (see Clean Power Plan EGs, section VIII). In this proposed rule, the proposed approach to link from the mass-based trading federal plan to state plans could result in linking of the federal plan to state plans that include non-affected emission sources. The EPA requests comment on this proposed approach.
The EPA believes that a broad trading region provides greater opportunities for cost-effective implementation of reductions compared to trading limited to a smaller region. The proposed approach to interstate trading is intended to strike a reasonable balance between providing the opportunity for a wide interstate trading system while maintaining the integrity of the linked programs. The agency requests comment on the proposed approach to interstate trading linkages in the federal plans.
Whether the EPA ultimately finalizes rate-based or mass-based federal plans, the agency believes that the ERC market and the allowance market would be competitive. The opportunities for interstate trading detailed above would reduce any potential for firms to exercise market power in the ERC market or allowance market. The EPA requests comment on this expectation of a competitive ERC market and a competitive allowance market, and comment on potential program design choices that could address any identified market power concern. The EPA intends to provide information to the market and the public, consistent with other trading programs that the agency administers, as detailed in sections IV and V of this preamble, for the rate-based and mass-based approaches, respectively.
A transparent and well-functioning allowance or ERC market is an important element of a mass-based or rate-based trading program. The EPA has over 20 years of experience implementing emissions trading programs for the power sector and based on that experience, believes the potential or likelihood of market manipulation is fairly low. Nonetheless, the EPA is evaluating the options for providing oversight of the allowance or ERC markets that may be established through the final EGs and federal plans. This could include engaging with other federal and state agencies as appropriate, and potentially with third parties, in conducting market oversight. The agency requests comment on appropriate market monitoring activities, which may include tracking ownership of allowances or ERCs, oversight of the creation and verification of credits, and tracking market activity (
The final EGs specify the concern of leakage, which is defined in section VII.D of the final EGs as the potential of an alternative form of implementation of the BSER (
In the final EGs, the EPA also discussed the concern that CO
The EPA requests comment on the proposed treatment of leakage and of interstate effects under both the proposed rate-based federal plan approach and the proposed mass-based federal plan approach, and as part of the corresponding proposed model rules.
The EPA outlined and initiated the CEIP in the final EGs (see section VIII.B.2 of the final EGs). The program is designed to incentivize investment in certain types of RE projects, as well as demand-side energy efficiency (EE) projects implemented in low-income communities. These RE projects must commence construction, and these EE projects must commence implementation after the date of submission of a final plan to the EPA by the state they are located on or benefitting, or after September 6, 2018 for those states on whose behalf the EPA is implementing the federal plan, and will receive incentives for the MWh they generate or the end-use energy demand reductions they achieve during 2020 and/or 2021. The CEIP also provides an additional incentive to drive investment in demand-side EE projects implemented in low-income communities. The EPA proposes to apply the CEIP in all states subject to either a rate-based or mass-based federal plan. The EPA's proposed approaches to implementing the program in the rate-based and mass-based federal plans are detailed in sections IV and V of this preamble, respectively.
Fossil fuel-fired EGUs are by far the largest emitters of GHGs among stationary sources in the United States, primarily in the form of CO
The EPA implements a separate program under 40 CFR part 98 called the Greenhouse Gas Reporting Program
The EPA prepares the official U.S. GHG Inventory to comply with commitments under the United Nations Framework Convention on Climate Change (UNFCCC). This inventory, which includes recent trends, is organized by industrial sectors. It provides the information in Table 3 of this preamble, which presents total U.S. anthropogenic emissions and sinks
Total fossil energy-related CO
In addition to preparing the official U.S. GHG Inventory, which represents comprehensive total U.S. GHG emissions and complies with commitments under the UNFCCC, the EPA collects detailed GHG emissions data from the largest emitting facilities in the United States through its GHGRP. Data collected by the GHGRP from large stationary sources in the industrial sector show that the utility power sector emits far greater CO
For the Clean
When considering and understanding applicability, the following definitions may be helpful. Simple cycle
We note that certain affected EGUs are exempt from inclusion in a state plan and this federal plan. Affected EGUs that may be excluded under the EGs are those that (1) Are subject to subpart 40 CFR part 60, subpart TTTT as a result of commencing modification or reconstruction; (2) are SGUs or IGCC that are currently and always have been subject to a federally enforceable permit limiting net-electric sales to one-third or less of its potential electric output or 219,000 MWh or less on an annual basis; (3) are non-fossil units (
The EPA also requests comment on an alternative compliance pathway that could be available to units under a mass-based approach. The ways that the approach could be implemented are further outlined in the Alternative Compliance Pathway for Units that Agree to Retire Before a Certain Date Technical Support Document (TSD). Under this approach, two basic requirements would need to be met. The first is that the unit would have to take a commitment that it would retire on a date on or before December 31, 2029. The second is that the unit would have to demonstrate that it will take an enforceable emission limitation that would assure that the overall state emission goal is met. The TSD explores ways that this approach could be implemented, including ways that the enforceable emission limitation could be calculated and implemented. The EPA requests comment on whether this approach should be available for all units or limited to small units (
The applicability of this proposed federal plan follows the same applicability criteria as the final EGs. The rationale for these criteria is provided in section IV.D of the Clean Power Plan. We are not reopening the criteria or rationale here.
In the federal plan Affected EGU TSD, the EPA lists all applicable affected EGUs according to our records from the National Electric Energy Data System (NEEDS), Energy Information Administration (EIA), and comments from the Clean Power Plan. In this TSD, each affected EGU is assigned its proposed applicable standards if a federal plan were to be promulgated for that affected EGU at any time. The EPA requests comments and updates to this list of affected units. Section VI.C of the final EGs describes the data used in setting the standards and how an inventory of affected units has been compiled.
In accordance with the schedule set out in the EGs, the federal plan is proposed to be implemented in a phased approach. The first period, corresponding to the Interim Period in the EG, is proposed to run from beginning of calendar year 2022 until end of calendar year 2029 (January 1, 2022 to December 31, 2029). The Final Period would run from beginning of calendar year 2030 (January 1, 2030) indefinitely into the future. The first period is proposed to be comprised of three “compliance periods,” set by calendar year. The first compliance period will be from January 1, 2022 to midnight, December 31, 2024 (3 calendar years). The second compliance period will be from January 1, 2025 to midnight, December 31, 2027 (3 calendar years). The third compliance period will be from January 1, 2028 to midnight, December 31, 2029 (2 calendar years).
Under the EGs, midnight, December 31, 2029 marks the end of the Interim Period, and the beginning of the Final Period. The EPA proposes that the compliance periods in the Final Period will each be 2 calendar years. Thus, the first compliance period after 2030 would be from January 1, 2030 to midnight, December 31, 2031. The second compliance period would be from January 1, 2032 to midnight, December 31, 2033. This would repeat accordingly unless changed by the EPA through a revision to the federal plan or other action.
The EPA recognizes that the compliance periods provided for in this rulemaking are longer than those historically and typically specified in CAA rulemakings. As reflected in long-standing CAA precedent, “[t]he time over which [the compliance standards] extend should be as short term as possible and should generally not exceed one month.”
Prior to the beginning of the first compliance period in 2022, the agency intends to establish the infrastructure for operating a federal trading program and to work closely with affected EGUs in the states where the federal plan is promulgated prior to the start of the first compliance period in 2022. We request comment on whether it would be possible to grant, on a case-by-case basis, certain affected EGUs, particularly small entities, additional time to come into compliance, and to request additional input from the public as to the design of such flexibility that would be compatible with the EGs and a federal plan that implements a trading system.
The EPA recognizes that it is important to ensure a degree of liquidity in compliance instruments in either of the proposed trading approaches, while also maintaining the stringency required by the final EGs. A number of aspects of the rate-based and mass-based programs would assist with this, including allocation methods or rules, mechanisms to place allowances or credits into the market relatively early, requirements for public transparency of information related to allowance, or credit issuance, tracking, transfers and holdings. The EPA solicits comment on other approaches to ensure market liquidity while continuing to meet the stringency of the final EGs.
The proposed federal plan has been designed to ensure that, to the greatest extent possible, implementation would not interfere with the power sector's ability to maintain electric reliability.
There are many features of the electricity system that ensure that electric system reliability will be maintained. For example, in the Energy Policy Act of 2005, Congress added a section to the Federal Power Act to make reliability standards mandatory and enforceable by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC), the Electric Reliability Organization which FERC designated and oversees. Along with its standards development work, NERC conducts annual reliability assessments via a 10-year forecast and winter and summer forecasts; audits owners, operators and users for preparedness; and educates and trains industry personnel. Numerous other entities such as FERC, U.S. Department of Energy (DOE), state public utility commissions (PUCs), independent system operators and regional transmission organizations (ISOs/RTOs), and other planning authorities also consider the reliability of the electric system. There are also numerous remedies that are routinely employed when there is a specific local or regional reliability issue. These include transmission system upgrades, installation of new generating capacity, calling on demand response, and other demand-side actions.
Additionally, planning authorities and system operators constantly consider, plan for and monitor the reliability of the electricity system with both a long-term and short-term perspective. Over the last century, the electric industry's efforts regarding electric system reliability have become multidimensional, comprehensive and sophisticated. Under this approach, planning authorities plan the system to assure the availability of sufficient generation, transmission, and distribution capacity to meet system needs in a way that minimizes the likelihood of equipment failure.
The EPA's approach in this proposed federal plan builds on the foundation provided in the EGs' determination of the BSER to ensure that the final federal plan, like the final EGs, does not interfere with the industry's ability to maintain reliability of the nation's electricity supply. First, the federal plan, like the EGs, provides more than 6 years before reductions are required and an 8-year period from 2022 to 2029 to meet interim goals. This allows time for planning and steady, measured implementation.
Second, the federal plan is a market-based trading program which will allow affected EGUs the opportunity to buy and sell emissions credits or allowances as well as bank them. The EPA's proposed federal plan includes two alternative approaches: A mass-based trading program and a rate-based trading program. Trading programs of both types have many positive attributes. Among them is that they help to ensure that imposition of the federal plan will not interfere with the industry's ability to maintain the reliability of the nation's electricity supply. Such a program does not restrict unit-level operational decision-making beyond requiring units to hold a sufficient number of tradable permits (
Third, just as we have required the states to do in developing state plans, the EPA is considering reliability as a part of developing this federal plan. For example, the EPA will consult with planning authorities. The EPA will work with the ISO/RTO Council to convene a face-to-face meeting for planning authorities with the EPA during the comment period to discuss any concerns or other feedback on the federal plan from those entities. This meeting will help to ensure that the EPA is taking into consideration any concerns about the relationship of this rulemaking to the ability of the industry to maintain electric reliability across the country as we finalize the federal plan. It will give the planning authorities an opportunity to hear directly from the EPA how the federal plan is designed and gives the planning authorities an opportunity to voice concerns and ask questions. This will help inform comments that planning authorities may submit to the docket.
In the final Clean Power Plan EGs, the EPA laid out the availability of a reliability safety valve that could be used if an unanticipated catastrophic emergency caused a conflict between
The EPA, DOE, and FERC have agreed to coordinate efforts to help ensure continued reliable electricity generation and transmission during the implementation of the final EGs and the final federal plan in any state that does not have an approved state plan. The three agencies have developed a coordination strategy that reflects their joint understanding of how they will work together to monitor implementation. The three agencies will work together to monitor implementation, share information and resolve any difficulties that may be encountered.
The EPA is not proposing to include an allowance set-aside, or similar mechanism in a rate-based approach, to address reliability issues in the federal plan; however, we request comment on including such a set-aside in the context of a mass-based approach. The EPA requests comment specifically on creation of an allowance set-aside for the purpose of making allowances available in emergency circumstances in which an affected EGU was compelled to provide reliability critical generation and demonstrated that a supply of allowances needed to offset its emissions was not available.
The set-aside would be in addition to the proposed set-asides that are detailed in section V.D in this preamble. The EPA would set aside allowances in each state under the mass-based federal plan, and if a reliability issue is perceived by the EPA, DOE and FERC coordinated monitoring process discussed above, the EPA would distribute allowances from the set-aside to support affected EGUs during or after an unforeseen, emergency reliability event. If there were unused allowances remaining in the set-aside, then the EPA would distribute them to affected EGUs pro rata based on the allocation approach that is detailed in section V.D of this preamble. The EPA requests comment on all elements of such an approach, including what events would trigger the need for allowances from the reliability set-aside; eligibility criteria to receive the set-aside allowances; the size of the set-aside; and the timing of distribution of allowances from the reliability set-aside. Additionally, the EPA requests comment on how a reliability “set-aside” approach could be implemented in the rate-based federal plan.
As detailed later in this preamble, the EPA proposes in the federal plan to implement a CEIP, which was established in the EGs to reward investment in certain clean energy projects that achieve MWh results during 2020 and 2021 (see sections IV and V of this preamble for the proposed approach to implement this incentive program in the rate-based and mass-based federal plans, respectively). Implementation of the CEIP in the federal plans would create ERCs and allowances before 2022, allowing for creation of banks that could be used in the event of an unforeseen, emergency reliability issue. The EPA requests comment on the potential for these banks of ERCs and allowances to support reliable electricity generation and transmission to be utilized in the event of this kind of reliability emergency.
In the EGs, the EPA suggested that to ensure that emission reductions are realized, it is important that construction, operations and other skilled work undertaken pursuant to state plans is performed to specifications, and is effective, safe, and timely. The EPA asks for comments as to whether the federal plan should encourage EGUs to ask for a demonstration that the work undertaken under a federal plan is performed by a proficient workforce. A good way to ensure such a workforce is to require that workers have been certified by: (1) An apprenticeship program that is registered with the U.S. Department of Labor (DOL), Office of Apprenticeship or a state apprenticeship program approved by the DOL; (2) a skill certification aligned with the DOE Better Building Workforce Guidelines and validated by a third party accrediting body recognized by DOE; or (3) other skill certification validated by a third party accrediting body.
Section 111(d)(2) of the CAA provides, “In promulgating a standard of performance under a plan prescribed under this paragraph, the Administrator shall take into consideration, among other factors, remaining useful lives of the sources in the category of sources to which such standard applies.” 42 U.S.C. 7411(d)(2). This language tracks similar language in CAA section 111(d)(1) with respect to state plans. In the final EGs, we explained how the Guidelines permit states in applying a standard of performance in their state plans to consider the remaining useful life of a facility. We determined that it was appropriate to specify that the general variance provisions in 40 CFR 60.24(f) should not apply to the class of affected facilities covered by these Guidelines. We concluded that facility-specific factors and in particular, remaining useful life, do not justify a state making further adjustments to the performance rates or aggregate emission goal that the Guidelines define for affected EGUs in a state and that must be achieved by the state plan.
Because the Guidelines do not allow for states to deviate from state goals based on remaining useful life, the EPA does not believe such goal adjustments are necessary or appropriate in the federal plan either. Nonetheless, this does not obviate the requirement that the EPA itself, in the design of its federal plan, consider, among other factors, the remaining useful lives of the affected facilities. The agency therefore proposes the following analysis of this factor.
Congress added the “remaining useful lives” factor to CAA section 111(d)(2) in the 1977 CAA Amendments. Congress did not provide in the statute any direction on how or to what degree “remaining useful lives” of facilities subject to a section 111(d) federal plan is to be considered. As discussed in the preamble to the final EGs, Congress' intent in enacting the provision was to allow for older facilties with short remaining useful lives to not be required to install capital-intensive pollution control devices to meet emission standards that would only be used for a short period of time before a plant ceased operation. A House of Representatives report on a predecessor bill to the enacted statute stated, “Older plants with relatively short remaining useful lives might have chosen to cease operation if the
Further, the statute provides that this factor is one “among other factors” that the agency is to consider in promulgating a standard of performance. Congress provided no guidance in the statute as to what those other factors could be. The inclusion of unspecified factors that the agency may determine for itself to consider, along with the use of the term “consider,” highlights that Congress intended to give the agency a substantial degree of discretion in determining how the “remaining useful lives” factor is considered. The statute does not require, and Congress did not intend, that this consideration mandate the agency to prevent all premature retirements of affected EGUs, to impose no emission requirements on older affected EGUs, or to ensure that profitability is maintained at all times for all affected EGUs. Congress knew how to explicitly exempt older plants from CAA requirements at the time of the 1977 Amendments. For example, Congress excluded plants in existence before August 7, 1977 from the preconstruction requirements of the prevention of significant deterioration (PSD)/non-attainment new source review (NSR) program,
This view also accords with past agency practice in implementing a similar provision. In the 1977 Amendments, Congress listed “remaining useful life” as a factor for consideration in the visibility program under section 169A. 42 U.S.C. 7491. The “remaining useful life of the source” is one of several enumerated factors that the state or the EPA is to consider in determining the best available retrofit technology (BART) for a particular source. Consistent with congressional purpose, the EPA has implemented this factor in the regional haze program for many years through the BART guidelines, in appendix Y to 40 CFR part 51. In the context of the visibility program, we have interpreted this provision to mean that the remaining useful life should be considered when calculating the annualized costs of retrofit controls.
Consistent with legislative intent and past agency practice, we propose that the federal plan adequately considers “remaining useful lives” of affected EGUs by providing for trading and other flexibilities authorized in the EGs. To summarize, these include: Relatively long periods for affected EGUs to come into compliance, the ability to credit early action, the use of emissions trading, the use of multi-year compliance periods, and the ability to link to other federal or state plans to create larger emissions markets. The federal plan is proposed to include a Clean Energy Incentive Program as provided for in the EGs, which will credit early action and ease compliance in the initial years of the program. These tools will create economic incentives that reward over-performance of some affected EGUs, and allow others to simply acquire credits or allowances to comply with their emission standard, thereby avoiding the need for installation of costly pollution controls at sources with a short remaining life.
Thus, the proposed federal plan is designed in such a way that it adequately, and inherently, takes into account the remaining useful lives of affected EGUs. It provides substantial compliance flexibility, including means of avoiding the need to make extensive capital investments in control technologies that could not be recouped during the remaining useful lives of a facility.
By relying on either rate- or mass-based emission trading, the proposed federal plan capitalizes on the inherent flexibility available through market-based techniques. In effect, under a trading program with repeating compliance periods, a facility with a short remaining useful life has a total outlay that is proportionately smaller than a facility with a long remaining useful life, simply because the first facility would need to comply for fewer compliance periods and would need proportionately fewer ERCs or allowances than the second facility. Buying ERCs or allowances as a compliance method could avoid excessive up-front capital expenditures that might be unreasonable for facilities with short remaining useful lives, and therefore addresses the consideration of “remaining useful lives.” Buying ERCs or allowances as a compliance method also would reduce the potential for stranded assets.
In addition, the timing of the federal plan limits the immediate costs of compliance, particularly for facilities that have useful lives ending before 2022, but also for facilities that have useful lives ending before 2030. There are no compliance obligations for affected EGUs under this federal plan until 2022, when the first compliance period begins. At that point, the agency is following the glide path provided for in the EGs, which begins with relatively higher emission targets that will slowly strengthen over the interim performance period from 2022-2029 through three multi-year compliance periods. The final, most stringent, compliance obligation does not begin until 2030.
Further, unlike state plans that can be more stringent under CAA section 116, the federal plan is no more stringent than the EGs, and, as explained in the EGs, the Guidelines reflect a reasonable, rather than a maximum possible, implementation level for each building block in order to establish overall goals that are achievable. As discussed in the
Under the proposed federal plan, title V permits for sources with affected EGUs will need to include any new applicable requirements that the plan places on the affected EGUs. The EPA, however, is not proposing any permitting requirements independent of those that would be required under title V of the CAA and the regulations implementing title V, 40 CFR parts 70 and 71.
The EPA anticipates that, given the nature of the units covered by the proposed federal plan, most of the sources at which they are located are already or will be subject to title V permitting requirements. For sources subject to title V, the requirements applicable to them under the proposed federal plan will be “applicable requirements” under title V and, therefore, will need to be addressed in the title V permits. For example, requirements under the proposed federal plan concerning designated representatives, monitoring, reporting, and recordkeeping, the requirement to either meet an emission rate (including through holding ERCs (rate-based approach)), or to hold allowances covering emissions (mass-based approach) will be “applicable requirements” to be addressed in the permits.
The EPA does not believe this approach is affected by the Supreme Court's decision in
The title V permits program is structured to provide flexibility for market-based approaches, such as allowance trading programs under the federal plan, including flexibility to make changes under such programs without necessarily requiring a formal permit revision. For example, the title V regulations provide that a permit issued under title V shall include, for any “approved * * * emissions trading or other similar programs or processes” applicable to the source, a provision stating that no permit revision is required “for changes that are provided for in the permit.” 40 CFR 70.6(a)(8) and 71.6(a)(8). Consistent with this provision in the title V regulations, the proposed federal plan regulations include a provision stating that no permit revision shall be required for the allocation, holding, deduction, or transfer of allowances once the requirements applicable to such allocations, holdings, deductions, or transfers of CO
As a further example of flexibility under title V, and consistent with 40 CFR 70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B), the EPA is proposing that any changes that may be required to an operating permit with respect to a trading program under the federal plan may be made using the minor permit modification procedures of the title V rules. The EPA proposes that such changes may include the initial changes needed to the title V permit to establish the applicability of the trading program to the source, specify the covered units, and to include other permit terms that may be needed for implementation, including the general approach for monitoring and reporting. The minor permit modification procedures could also be used for any subsequent changes
The EPA believes that the approach to permitting requirements we are proposing here, which imposes no additional permitting requirements independent of title V and provides for the use of minor permit modification procedures, will streamline the process for sources already required to be permitted under title V and for permitting authorities. If there are any sources that would become newly subject to title V as a result of the requirements of this proposed federal plan, the initial title V permit that would be issued pursuant to 40 CFR 70.7(a) or 71.7(a) would address the federal plan requirements, when finalized.
The EPA notes that the approach to title V permitting that is being proposed is somewhat similar to the approach adopted in the final CSAPR.
The EPA also notes that the applicable requirements of this proposed federal plan would apply to a source and are independently enforceable regardless of whether they have yet been included in the source's Title V permit.
The NSR program is a preconstruction permitting program that requires major stationary sources of air pollution to obtain permits prior to beginning construction. The requirements of the NSR program apply both to new construction and to modifications of existing major sources. Generally, a source triggers these permitting requirements as a result of a modification when it undertakes a physical or operational change that results in a significant emission increase and a net emissions increase. NSR regulations define what constitutes a significant net emissions increase, and the concept is pollutant-specific.
In the final EGs, the EPA recognized that, as part of its CAA section 111(d) plan, a state may impose requirements that require an affected EGU to undertake a physical or operational change to improve the unit's efficiency that results in an increase in the unit's dispatch and an increase in the unit's annual emissions. If the emissions increase associated with the unit's changes exceeds the thresholds in the NSR regulations for one or more regulated NSR pollutants, including the netting analysis, the changes would trigger NSR. We noted that while there may be instances in which an NSR permit would be required, we expect those situations to be few.
The EPA believes the analysis of NSR applicability is basically the same for sources under a CAA section 111(d) federal plan. That is, it is conceivable that a source under a federal plan may choose, as a means of compliance with either a rate-based or mass-based approach, to undertake a physical or operational change to improve an affected EGU's efficiency that results in a significant net emissions increase of a regulated NSR pollutant. This would trigger NSR. However, as with state plans, the EPA believes that these situations will be few.
After the proposal for the Clean Power Plan was published in June of 2014, the U.S. Supreme Court issued its opinion in
The EPA will invite comment on potential scenarios in which affected EGUs, particularly small entities, could be subject to the requirements of the NSR program as a result of taking compliance measures under the federal plan, and any ideas for harmonizing or streamlining the permitting process for such sources that are consistent with judicial precedent. However, the EPA is not proposing any changes to the NSR program in this action, and the agency is not reopening or reconsidering any prior actions or determinations related to NSR in this action. Any comments related solely to the NSR program will be considered outside the scope of this proposed rule.
Existing fossil fuel-fired EGUs, such as those covered in this proposal, are or will be potentially impacted by several other rules recently finalized or proposed by the EPA.
Under either a rate-based or mass-based trading program, the EPA anticipates that there may be situations in which individual parties are affected by decisions of the agency. For example, under a rate-based plan, a determination may be made that an eligibility application by an ERC provider is denied. And, for set-asides in the mass-based program, an affected EGU may believe that its allowance allocation amount was miscalculated. Similar to prior trading programs, the agency believes it would be efficient and potentially avoid the need for recourse to litigation to provide an administrative appeals process. Therefore we are proposing, and requesting comment on, the use of the regulations for appeals procedures set forth in 40 CFR part 78, to provide for the adjudication of certain disputes that may arise during the course of implementation of a federal plan under CAA section 111(d). We also propose to revise part 78 to accommodate such appeals. The part 78 procedures cover prior CAA emission trading programs and were specifically designed with these types of disputes in mind.
The persons eligible to file such appeals would be designated representatives as defined in this proposed rule and other “interested persons” as defined in part 78. The filing of an appeal and the exhaustion of administrative remedies under part 78 would be a prerequisite to seeking judicial review. For purposes of judicial review, final agency action would occur only when an agency decision under the federal plan listed as appealable under part 78 has been issued, and the procedures of part 78 for appealing the decision are exhausted.
The actions we propose to list as appealable under the part 78 procedures are as follows:
In the case of the rate-based federal plan: Decisions on an eligibility application for ERCs; decisions regarding the number of ERCs generated; decisions on the transfer of ERCs; decisions on the disallowance of ERCs for compliance; decisions that there has been an excess of emissions requiring a 2-for-1 ERC administrative compliance penalty; decisions regarding deduction or surrender of ERCs for compliance from affected EGUs' compliance accounts; decisions on the accreditation of independent verifiers; the use of error corrections regarding information submitted by ERC providers, affected EGUs, or other ERC account holders; and the finalization of compliance period emissions data, including retroactive adjustment based on audit or other investigation.
In the case of a mass-based federal plan: Decisions on an eligibilty application for set-aside allowances; decisions regarding the allocation of allowances to affected EGUs; decisions regarding the allocation of allowances from set-asides; decisions on the transfer of allowances; decisions regarding the finalization of emissions data by affected EGUs during compliance periods; decisions making error corrections to information submitted by affected EGUs and other account holders; decisions that there has been excess emissions requiring a 2-for-1 allowance administrative compliance penalty; and decisions regarding the deduction or surrender of allowances for compliance from affected EGUs' compliance accounts.
We request comment on this list of actions for both types of approaches to the federal plan, and whether there are other decisions that may be made in the course of implementation of the federal plan that are party-specific that would be appropriate to list as appealable under part 78. We also request comment on whether it would be appropriate for the EPA to finalize an administrative appeals process that differs in any way from that offered under part 78, or in addition to that offered under part 78. If so, we request comment broadly on all aspects of the alternative or additional adminsitrative appeals process, including with respect to any structural, procedural, subtantive, and timing requirements it should include, who should have access to it and in what manner, and how it would differ from part 78. Finally, we request comment on whether, similar to other programs identified in 40 CFR 78.1(a)(1), the agency should make the procedures of part 78 available to any actions of the Administrator under the comparable state regulations approved as a part of a state plan under the EGs.
The EPA is co-proposing two distinct forms of emissions trading as the mechanism for federal implementation of standards of performance that achieve the emission performance levels determined by application of the BSER in the Clean Power Plan EGs. Both proposals are “emission standard” approaches as defined in the EGs, and the EPA is not proposing an approach like the “state measures” approach that is also available to states in the final EGs. The EPA has legal authority to establish either of the proposed trading systems as a federal plan under CAA section 111(d)(2). We discuss this topic briefly here and invite public comment. The EGs discussed the role of emissions trading in the BSER,
Section 111(d)(2) provides that “[t]he Administrator shall have the same authority [ ] to prescribe a plan for a State in cases where the State fails to submit a satisfactory plan as he would have under section 7410(c) of this title in the case of failure to submit an implementation plan . . .” 42 U.S.C. 7411(d)(2)(A).
The phrase “same authority to prescribe” indicates that Congress viewed the EPA's authority to issue a federal plan for designated pollutants under CAA section 111(d) as, in some sense, co-extensive with its authority to issue a FIP for National Ambient Air Quality Standards (NAAQS) pollutants under CAA section 110. This authority under CAA section 111, of course, must be understood in reference to the purpose of that section (
Over the several decades of implementation of the CAA, the courts, and the EPA, have addressed the nature and scope of CAA section 110 authority.
By the same token, if there are clear limits to the EPA's CAA section 110(c) authority, those too, would arguably carry over to CAA section 111(d)(2). For instance, CAA section 110(c)(1) ties the EPA's authority to promulgate a final FIP for a state to the EPA's predicate action on a SIP (or lack thereof): Generally, either an action disapproving a plan, or a finding that a state has failed to submit a plan. However, even here, as the Supreme Court has recognized, “the plain text of the CAA grants EPA plenary authority to issue a FIP `at
Congress gave the EPA the same authority to prescribe a plan under CAA section 111(d)(2) as it possesses under CAA section 110(c). The EPA believes this authority is the “same” in the sense described above and in the case law.
The agency received comments on the proposed EGs from commenters who stated that the EPA cannot require states to implement the building blocks that make up the BSER; for example, ordering re-dispatch to natural gas-fired units, or ordering the construction of RE projects. These commenters went on to say that the EPA itself would have no authority to order these types of actions under a federal plan. As we explained in the Legal Memorandum for the final EGs, and reiterate here, the premise of these comments is incorrect. The EPA is not requiring the implementation of the BSER or the building blocks in the EGs. Even where the EPA is directly implementing standards of performance in a federal plan, the agency will not, and need not, attempt to order sources to implement the measures that comprise the BSER. Rather, as set forth in the co-proposed federal plans discussed in sections IV and V of this preamble, the EPA would set emission standards for each of the affected EGUs in the federal plan state, provide mechanisms for their implementation and enforcement, and otherwise leave to the owners and operators of the affected EGUs the decisions about what measures they want to take to comply with the emission standard. Though the emission standards will be federally enforceable, as under a state plan, sources may achieve them through implementation of measures in the BSER, or any other method.
Thus, the question whether the EPA would have the authority to directly order the implementation of the measures in the building blocks in this proposed federal plan is not only not relevant but represents a categorical misunderstanding of the nature of the BSER in relation to the imposition of standards of performance under a CAA section 111(d) plan. To illustrate this, by the same token the EPA could not enforce many logistical aspects of a control requirement such as a scrubber—for instance, the EPA does not need to assert the authority to order into existence companies that manufacture scrubbers, or order their construction or delivery on a certain schedule. The EPA need not in setting emission standards have before it all of the information regarding manufacturing, transportation of parts, or other logistical requirements to ensure that each scrubber gets constructed and delivered to a source. Similarly, the EPA here does not, and need not, propose an implementation approach of directly intervening to re-dispatch certain units, construct new RE projects, or take other measures, either included in the BSER or not. The agency determined the BSER and emission performance levels in the EGs on a reasonable assumption that all of those things can actually happen. In providing for the implementation of federally enforceable standards of performance in the federal plan proposed in this action, the agency is ensuring that these things will happen.
The use of market techniques such as emission trading is well-supported in the CAA and has many regulatory precedents. The EPA discussed this history, and the reason why trading is a supportable method of
The 1990 CAA Amendments added broad authorizations for the use of market techniques in several sections of the statute, including Title I. States were provided express authority to use such approaches in their NAAQS implementation plans under CAA section 110(a)(2)(A): “Each [state] plan shall include enforceable emission limitations and other control measures, means, or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights) . . . .” 42 U.S.C. 7410(a)(2)(A). The EPA was given similar authority in the definition of a “Federal Implementation Plan” in CAA section 302, which defines that term as an EPA-promulgated plan, which “includes enforceable emissions limitations or other control measures, means or techniques (including economic incentives, such as marketable permits or auctions of emissions allowances), and provides for attainment of the relevant national ambient air quality standard.” 42 U.S.C. 7602(y). Section 111(d)(2) of the CAA provides the EPA the same authority to prescribe a federal plan under CAA section 111 as it would have to promulgate a FIP under CAA section 110(c). Thus, the EPA believes the plain language of the statute authorizes the use of market techniques in CAA section 111(d) federal plans.
However, even if one were to view this language as not wholly unambiguous with respect to the scope of federal authority under CAA section 111, the EPA believes that CAA section 111, in conjunction with authorizations and endorsements of market techniques throughout the CAA, and other indicia of congressional intent, strongly support the view that market techniques are within the EPA's authority to promulgate a federal plan under CAA section 111(d).
Case law throughout the history of the CAA has generally confirmed the legal viability of emissions trading as an implementation measure so long as the trading ultimately achieves the emission reduction goals of the statute.
With the increasing recognition of the utility of trading, crediting, and averaging to meet emission reduction goals efficiently, the EPA set forth a comprehensive policy on trading in 1986. Emissions Trading Policy Statement; General Principles for Creation, Banking and Use of Emission Reduction Credits, 51 FR 43814 (December 4, 1986) (hereinafter “ERC Policy”). In the ERC Policy, the EPA stated that it “endorses emissions trading and encourages its sound use by states and industry to help meet the goals of the CAA more quickly and inexpensively.” At the same time, based on lessons learned from its earlier 1982 trading policy, the EPA took steps to tighten its policies on the use of “bubbles” to ensure environmental integrity of trading, particularly in nonattainment areas. The agency emphasized the requirements of enforceability, tracking (and preventing double-counting), determining the appropriate baseline from which to measure emissions, and demonstration of actual air quality benefits.
The use of an emissions trading system for CO
By the time of the 1990 CAA Amendments, as discussed above, Congress was comfortable enough with the efficacy of market techniques that they were broadly authorized for use in SIPs and FIPs for NAAQS.
Since the 1990 Amendments, the EPA has established three of its most robust trading programs—the Federal NO
As noted in the rulemaking action for the final EGs, the EPA has instituted or authorized the use of emissions trading programs twice in the past under CAA section 111(d). The EPA authorized NO
The agency believes these legal and administrative precedents for federal trading programs under the CAA going back decades amply support its decision to propose two forms of emission trading as the method of implementation of the Clean Power Plan EGs in the federal plan. Notably, emissions trading is particularly appropriate with respect to a global pollutant such as CO
Finally, the Supreme Court has affirmed the breadth of the agency's discretion under CAA section 111(d) to select the method by which it would control CO
This proposal is guided by the relevant cases and the experiences of the agency in implementing the CAA trading programs discussed above. The EPA invites comment on this discussion and the agency's interpretation that CAA section 111(d)(2) authorizes the two approaches to a federal plan proposed here.
The EPA's federal plan requirements for CO
This section describes the proposed rate-based federal plan and model trading rule and how each would be designed and operated, consistent with the EGs. For the federal plan, the EPA is proposing to limit the issuance of ERCs to designated categories of affected EGUs and to RE resources and nuclear generation (from new capacity and incremental capacity uprates) that are
In the Clean Power Plan the EPA identified a rate-based “emission standards” approach as an approvable method for state plans to implement the final EGs. In this approach the requirements for compliance rest solely on affected EGUs in the form of federally enforceable emission standards expressed as a rate of emissions of CO
As discussed in section III.D of this preamble above, the EPA proposes to implement a compliance schedule for the rate-based federal plan with multi-year compliance periods as follows: A 3-year period (2022 through 2024), followed by a 3-year period (2025 through 2027), followed by a 2-year period (2028 and 2029), for the Interim Period; and, commencing in 2030, successive 2-year compliance periods for the Final Period. In the Clean Power Plan, the EPA established CO
The EPA is proposing to use a glide path during the Interim Period for EGUs to provide a smooth transition to the final compliance periods after 2030. This approach is established in the final EGs. In Table 6 of this preamble, the applicable standards for each interim compliance period are listed.
The EPA is using the subcategorized rates in the rate-based trading approach because it allows ERCs to be fungible across jurisdictional borders and provides an incentive structure, as compared to other rate-based approaches, that facilitates implementation of measures identified as part of the BSER. Using subcategorized rates allows for: (1) Consistently applied emission rates for power plants of different types; and (2) free trading of fungible ERCs among all affected EGUs subject to the federal plan and within the federal trading program. The EPA solicits comments on whether the subcategorized rate approach is the preferred rate-based approach for the federal plan and model trading rule.
Under a rate-based emission standard approach in the federal plan, we are proposing that EGUs subject to the emission performance requirements for GHGs will either need to emit at or below their rate-based emission standard, or they will need to acquire ERCs to achieve compliance. An ERC is a tradable compliance unit representing one MWh of electric generation (or reduced electricity use) with zero associated CO
Under this proposed federal plan, ERCs will be issued by the EPA to four categories of entities: (1) Affected EGUs that perform at a rate below the applicable rate-based emission standard; (2) affected NGCC units for all generation (represents shifting generation from SGUs to NGCC units, as anticipated under Building Block 2); (3) new nuclear units and capacity uprates at existing nuclear units; and (4) RE providers that develop metered projects and programs whose results, in MWh, are quantified and verified according to
Because the goal of this rulemaking is the actual reduction of CO
The number of ERCs generated or needed for surrender by an affected fossil fuel-fired EGU is based on the CO
If the value calculated is positive, this indicates the number of ERCs that are being generated; conversely, a negative value indicates how many ERCs will need to be acquired to meet the unit's emission rate for that compliance period. ERCs will be issued on an annual basis to ERC providers (
As an example, assume a steam EGU operating in the second interim compliance period is subject to a rate standard of 1,500 lbs CO
The discussion in this subsection builds on and applies the definition, benefits, use, and determination of using ERCs from the final EGs (section VIII of the final EGs). We invite comment on use of the approach just described as a method of implementation of a federal plan and a model trading rule, and we request comment on any alternatives to this approach that still fall within the established criteria described in the Clean Power Plan EGs. Comments that solely relate to determinations finalized in the EGs will be considered outside the scope of this proposed rule.
Building Block 2 (BB2) of the BSER determination in the Clean Power Plan EGs describes shifting generation from SGUs to NGCC units because NGCC units generate electricity at a less carbon intensive rate. BB2 describes NGCC units generating at 75 percent of the unit's annual operating capacity. This level of generation, for most NGCC units, would represent an increase in annual generation from a 2012 baseline. For every hour of electricity generated by an NGCC unit beyond its 2012 baseline (
All affected NGCC generation will be credited, with ERCs, by a factor that represents the described emission reductions from incremental generation; ERCs credited in this way will be designated as Gas Shift ERCs (GS-ERCs) for clarity.
The number of GS-ERCs that an NGCC unit generates is a combination of three factors. The first is the GS-ERC Emission Factor. This emission factor represents how much better an individual NGCC's emission rate is compared against the fossil steam standard. This measures the emission reductions because of the BB2 shift in generation. The SGU standard used as reference here is as described above in section IV.B of this preamble and established in the BSER determination from the EGs of the least stringent region
The second factor is the Incremental Generation Factor. This factor represents the distribution of the increased NGCC generation across all NGCC generation. In essence, it is prorating the incremental NGCC generation over all NGCC generation. The Incremental Generation Factor is calculated by taking the number of MWh beyond the 2012 baseline needed for the corresponding region to reach 75 percent NGCC generation capacity and dividing it by the MWh that is 75 percent NGCC generation capacity, giving a factor. This factor can be summarized by the following expression:
The Incremental Generation Factor is a factor that the EPA will calculate and will be calculated for every compliance period based on the least stingent region's Incremental Generation Factor based on increased utilization of RE and its replacement of fossil fuel-fired generation (based on Building Block 3 of the Clean Power Plan EGs).
The third factor in calculating an NGCC unit's generaton of GS-ERC is the NGCC Generation. The NGCC Generation is the total net energy output generation of the affected NGCC unit during the year that ERCs are being calculated. The three factors combine to make the following equation:
The GS-ERC equation above gives the number of GS-ERCs that an NGCC unit will generate. The Incremental Generation Factor and GS-ERC Emission Factor combine to make the GS-ERC generating rate for the NGCC unit. This functions by the Incremental Generation Factor prorating all incremental NGCC generation and the GS-ERC Emission Factor designating the proportion of the incremental NGCC generation that will generate ERCs. The GS-ERC generating rate multiplied by the total NGCC Generation gives the total GS-ERCs generated by the NGCC unit for the year.
The EPA is proposing this approach, which provides GS-ERCs for all affected EGU NGCC generation but at a fractional, pro rated level, using the three factors above, for several reasons. This approach has the benefit of
In the Clean Power Plan the BSER determination for subcategory rates is calculated by using the least stringent region and applying the standards from that region on a national level. The determination of the BSER in the final EGs was a one-time determination and is not being altered, updated, or changed here. Rather, in this preamble the EPA is proposing to use the same regions and to apply the least stringent components to an NGCC unit's GS-ERC calculation at a national level (
The EPA also requests comment on whether the GS-ERC Emission Factor should be calculated on a unit by unit basis (as currently proposed) or be calculated based on the least stringent region's baseline 2012 average emission rate. This will simplify the practice of calculating and distributing GS-ERC generation, but would not reward the better performing NGCC units within the subcategory. In the GS-ERC TSD, the EPA used the regions' average emission rate to calculate a factor that would credit GS-ERCs to all NGCC units subject to the federal plan. For 2030 and beyond, this value is based on the Eastern Interconnect and is 0.08 GS-ERCs/MWh. So for every MWh that an NGCC unit generates it would be issued 0.08 GS-ERCs and, if this were the approach the EPA proposed, this would apply to every NGCC unit that would be subject to the federal plan.
In the GS-ERC TSD, the spreadsheet can be manipulated to show what an individual NGCC unit's GS-ERC Emission Factor would be in the proposed method. This is done by adjusting the cell for a year's Average GS-ERC Emission Factor to account for the individual NGCC unit's emission rate instead of the average NGCC emission rate.
The calculation of GS-ERCs for an NGCC unit is independent of the calculation of ERCs generated or owed against the NGCC standard. It is possible that an NGCC unit will owe ERCs against its assigned emission standard for every MWh generated, but still be generating GS-ERCs. GS-ERCs may only be used to meet steam generation units' compliance obligations.
As an example, an NGCC unit is connected to the grid and generates 1 million MWh of electric output for the first year of the final performance period. During this year it emits 850 million lbs of CO
When that equation is solved for the number of ERC MWh needed, the NGCC unit would need to acquire 102,464 ERCs to adjust its emission rate to its rate-based emission standard.
Additionally, the GS-ERC Emission Factor for this NGCC unit is calculated by using 771 lbs CO
This calculation results in a GS-ERC Emission Factor of 0.45. This is only an example. Because the Incremental Generation Factor is calculated by the EPA, it can be found in the GS-ERC TSD and is proposed to be 0.26. By using the GS-ERC Emission Factor and Incremental Generation Factor calculated above with the NGCC unit's generation for the year, the number of GS-ERCs for this NGCC unit can be calculated.
The calculation results in 117 thousand GS-ERCs being generated. Because an NGCC unit cannot use the GS-ERCs it generates to meet its compliance obligations, this NGCC unit will both generate ERCs (117,000 GS-ERCs) and owe ERCs (102,464 non-GS-ERCs against NGCC standard). This NGCC unit may sell (or otherwise transfer) or bank its GS-ERCs. If a GS-ERC is sold, those proceeds may, in turn, be used to acquire non-GS-ERCs to satisfy the NGCC unit's compliance obligations.
A GS-ERC may not be used to meet an NGCC unit's compliance obligation because they are generated to reflect incremental NGCC generation replacing a SGU's generation. The calculation to derive a GS-ERC represents this generation shift. If a GS-ERC were to be used for compliance for an NGCC unit it would represent a shift from one NGCC unit to another, which serves little purpose in achieving emission reductions.
The EPA requests comment on the proposed approach and requests comment and suggestions on other approaches for existing NGCC units to generate GS-ERCs at all times. The EPA is considering this methodology that GS-ERCs are generated for all NGCC generation because it ensures that all existing NGCC units are encouraged to run at a greater capacity. The EPA requests comment on alternative methods to account for NGCC units
This equation quantifies the reductions of the generation shift from fossil steam to NGCC units by the NGCC operating rate being evaluated against the fossil steam standard. For all incremental NGCC generation the NGCC operating rate is compared against two different standards: (1) The NGCC standard against which ERC generation is evaluated; and (2) the steam standard against which GS-ERC generation is evaluated. An evaluation against each standard is independent of one another and GS-ERCs, in this situation, are only available for fossil steam compliance purposes.
While having a baseline threshold for EGU generation to credit GS-ERCs against closely resembles the EPA's BSER determination, it enables a system in which GS-ERCs can be generated by replacing NGCC generation from one unit with NGCC generation from another. In this situation there is not necessarily any additional NGCC generation as a subcategory, but a shift in which NGCC units are generating electricity and to what degree. This allows for a situation in which GS-ERCs can be generated without achieving the anticipated reductions in CO
The EPA also requests comment on whether a distinct type of ERC that comes with the proposed restrictions (
Under the rate-based federal plan, the EPA is proposing to specify emission reduction measures used to adjust an emission rate that are eligible for ERC issuance under the federal plan. Specifically, the EPA is proposing that RE generation that meets the requirements for eligible resources in the EGs (as specified in section VIII.K of the final EGs), meets all other requirements related to ERC issuance in the EGs and this proposal, and falls into one of the following specific categories of RE resources (as specified in section V.E of the final EGs), are eligible to be issued ERCs: Wind, solar, geothermal power, and hydropower.
The EPA is proposing the inclusion of these measure types in the federal plan for the following reasons. These technologies, with the exception of nuclear, are part of the quantification of RE generation potential for the BSER. Thus, they are included in the quantification of CO
The agency requests comment on the inclusion of other emission reduction measures as eligible for ERC issuance under the rate-based federal plan. This may include other RE technologies not included above, such as distributed RE generation and various types of biomass. In this proposal, the EPA is also offering for comment a treatment option for biomass fuels, if it is included as an eligible measure under the federal plan (see below).
The EPA requests comment on the inclusion of various types of demand-side EE as eligible measures for ERC issuance under the federal plan, such as state and utility EE programs, project-based demand-side EE, state building codes, state appliance standards, and conservation voltage reduction. The agency also requests comment on the inclusion of CHP as an eligible measure under the federal plan. Later in this section, the agency has provided detailed requirements for the issuance of ERCs for CHP, and we request comment on these requirements for inclusion in the federal plan.
The EPA requests comment on the inclusion as eligible for ERC issuance under the federal plan of any other
The EPA acknowledges that as new technologies mature, there should be an avenue to add new technologies to this specified set of eligible measures under the federal plan. The agency requests comment on appropriate processes through which, after the federal plan is finalized, the EPA or stakeholders could demonstrate the appropriateness of new measure types and the EPA could evaluate and approve the demonstration so that a new measure type could be considered eligible for ERC issuance under the federal plan.
Under the rate-based model rule, the EPA is proposing that any emission reduction measure is eligible as long as the requirements for eligible resources in the final EGs (as specified in section VIII.K of the final EGs) and all other requirements related to ERC issuance under the model rule that are specified in the EGs and this proposal. In particular, these measures should be able to meet the requirements for EM&V as finalized in the final EGs section VIII.K and those proposed for the model rule in section IV.D.8 of this preamble. In this section, the EPA is also providing detailed requirements for CHP and waste heat power (WHP); these requirements are proposed under the model rule, and we request comment on their inclusion in the federal plan. We are requesting comment on the inclusion of biomass and an option for the treatment of biomass in both the proposed rate-based federal plan and proposed rate-based model rule.
As mentioned above, the EPA requests comment on the inclusion of biomass as an eligible measure for rate-based crediting. The EPA is also requesting comment on the following treatment option for biomass if biomass is included as an eligible measure. In the final EGs, the EPA recognizes that the use of some biomass-derived fuels can play an important role in controlling increases of CO
In addition to acknowledging such state programs, the EPA has undertaken a technical assessment of biogenic CO
If biomass is included as an eligible measure, we are taking comment on an option for biomass treatment under the rate-based federal plan, which would also potentially apply to eligible generation under the proposed mass-based model trading rule allowance set-aside and to the calculation of covered emissions for affected EGUs that are co-firing biomass.
This option offered for comment is to specify a list of pre-approved qualified biomass fuels. For example, the EPA could recognize the CO
The EPA also requests comment on options for how EGUs would demonstrate that feedstocks meet the requirements to be accepted as a pre-approved qualified biomass feedstocks. These requirements could include demonstration of certification or verification of practices that are additional to other monitoring, reporting and EM&V requirements discussed in this proposal, such as provision of sufficient credible analysis of carbon benefits, third party verification and/or certification, or a determination of the net biogenic CO
The EPA requests broad comment on the types of qualified biomass feedstocks that should be specified in the final model rule, if any. We request comment on the methods that we should specify in the final model rule for the measurement of the associated biogenic CO
The eligibility requirements for ERC resources discussed in this section meet the requirements outlined in the final EGs (see section VIII.K.2 of the final EGs). The agency in this proposal is including in the regulatory text for the model rule language related to the crediting of these other potential ERC resources, even though they are not being proposed as a part of the federal plan. Our intent is to provide states further direction through the model rule on how states may include this broader set of ERC-generating resources in a rate-based plan. To reduce confusion over the applicability of these provisions, the agency has added a note in the regulatory text to clarify that these resources, and provisions throughout the proposed subpart that are related to those resources, are not applicable in the case of a federal plan. Rather they are proposed as part of the model trading rule only. However, again, the agency requests comment on the inclusion of these resources in the federal plan.
The EPA is proposing with respect to the rate-based model rule that CHP units are eligible to generate ERCs. With respect to the federal plan, the EPA requests comment on the incorporation of non-affected CHP units. Electric generation from non-affected CHP units
The electrical generation from a non-affected CHP unit that can be used to adjust the CO
Where the ratio is limited to values between 0 and 1.
The CHP electrical CO
Where UTO is the useful thermal output from a counterfactual industrial boiler that would have existed to meet thermal load in the absence of the CHP unit.
This accounting approach takes into account the fact that a non-affected CHP unit is a fossil fuel-fired emission source, as well as the fact that the incremental CO
The EPA is proposing with respect to the rate-based model rule that WHP units are eligible to generate ERCs. With respect to the federal plan, the EPA requests comment on the incorporation of non-affected WHP units. WHP units that meet the eligibility criteria under section VIII.K.1 of the Clean Power Plan preamble may be used to adjust the CO
The EPA proposes that the rate-based federal trading program use the agency's already-existing Allowance Tracking and Compliance System (ATCS). Under the proposed rate-based trading program, the federal trading program would be maintained in the EPA's existing data system. The ATCS would be used to track the trading of ERCs held by affected EGUs, as well as ERCs held by other entities. Specifically, the ATCS would track the generation of ERCs, holdings of ERCs in compliance accounts (
In the subsections that follow, the mechanisms by which a rate-based trading program would be implemented and administered are detailed. The EPA requests comment on each component of the trading system that is proposed in this preamble and the associated model rule, the trading program as a whole, and specifically requests comment on means to expedite the process of issuing ERCs, any minimum and maximum periods for which ERCs should be issued (
This section establishes the procedures for certifying and authorizing the designated representative, and alternate designated representative, of the owners and operators of the affected EGU and for changing the designated representative and alternate designated representative. These sections also describe the designated representative's and alternate designated representative's responsibilities and the process through which he or she could delegate to an agent the authority to make electronic submissions to the Administrator. These provisions would be patterned after the provisions concerning designated representatives and alternates in prior EPA-administered trading programs.
The designated representative would be the individual authorized to represent the owners and operators of each affected EGU in matters pertaining to the rate-based trading program. One alternate designated representative could be selected to act on behalf of, and legally bind, the designated representative and, thus, the owners and operators. Because the actions of the designated representative and alternate would legally bind the owners and operators, the designated representative and alternate would have to submit a certificate of representation certifying that each was selected by an agreement binding on all such owners and operators and was authorized to act on their behalf.
The designated representative and alternate would be authorized upon receipt by the Administrator of the certificate of representation. This document, in a format prescribed by the Administrator, would include: Specified identifying information for the covered source and covered EGUs at the source and for the designated representative and alternate; the name of every owner and operator of the affected EGU; and certification language and signatures of the designated representative and alternate. All submissions (
In order to change the designated representative or alternate, a new certificate of representation would have to be received by the Administrator. A new certificate of representation would also have to be submitted to reflect changes in the owners and operators of the affected EGU involved. However, new owners and operators would be bound by the existing certificate of representation even in the absence of such a submission.
In addition to the flexibility provided by allowing an alternate to act for the designated representative (
The rate-based trading program rules establish the procedures and requirements for using and operating the ATCS (which is the electronic data system through which the Administrator would handle ERC issuance, holding, transfer, and deduction), and for determining compliance with the ERC-holding requirements in an efficient and transparent manner. The ATCS provides a record of ownership, dates of ERC transfers, buyer and seller information, origin of ERCs, the serial numbers of ERCs transferred, and ERC type (
This federal plan and model rule's proposed tracking system and tracking systems that will be presumptively approvable for state plans fufill the criteria set forth in the final EGs. The EPA's tracking system includes provisions to ensure that ERCs issued to any eligible entity are properly tracked from issuance to submission by affected EGUs for compliance (where ERCs are “surrendered” by the owner or operator of an affected EGU and “retired” or “cancelled” by the Administrator or administering state regulatory body), to ensure they are used only once to meet a regulatory obligation. This is addressed through specified requirements for tracking system account holders, ERC issuance, ERC transfers among accounts, compliance true-up for affected EGUs,
The EPA received a number of comments from states and stakeholders on the Clean Power Plan about the value of the EPA's support in developing and/or administering tracking systems to support state administration of rate-based emission trading systems. As described above in section III.A of this preamble, the EPA is proposing, as part of both types of model trading rules, a federal trading platform that would allow state plans that are ready-for-interstate-trading to operate through a program in which the EPA provides the tracking and compliance system. This system will meet the requirements of the Clean Power Plan.
This section describes two types of ATCS accounts: Compliance accounts, which would be established by the Administrator for each affected EGU upon receipt of the certificate of representation for the source; and general accounts, which could be established by any entity upon receipt by the Administrator of an application for a general account. A compliance account would be the account in which any ERCs used by the affected EGU for compliance with the emissions limitations would have to be held until retired for compliance.
General accounts could be used by any person or group for holding or trading ERCs. However, ERCs could not be used for compliance with emissions limitations so long as the ERCs were held in, and not properly and timely transferred out of, a general account. To open a general account, a person or group would be required to submit an application for a general account, which would be similar in many ways to a certificate of representation. The application would include, in a format to be prescribed by the Administrator: The name and identifying information of the individual who would be the authorized account representative and of any individual who would be the alternate authorized account representative; an identifying name for the account; the names of all persons with an ownership interest with the respect to allowances held in the account; and certification language and signatures of the authorized account representative and alternate. The authorized account representative and alternate would be authorized upon receipt of the application by the Administrator. The provisions for changing the authorized account representative and alternate, for changing the application to take account of changes in the persons having an ownership interest with respect to ERCs, and for delegating authority to make electronic submissions would be analogous to those applicable to comparable matters for designated representatives and alternates. The EPA requests comment on these compliance mechanisms.
The EPA proposes that affected EGUs subject to this federal plan are required to meet compliance obligations by November 1 of the year following the end of the compliance period. For an affected EGU to meet its compliance obligations its average stack emission rate over the compliance period must be at or below its applicable rate standard, or the affected EGU must use ERCs to adjust its average stack emission rate to be at or below its applicable rate standard. An EGU's average emission rate over the compliance period will be calculated based on submitted data to ATCS. The compliance period average would be calculated by taking the measured CO
The EPA proposes to issue ERCs for ERC generating entities once per year. Thus, in a 3-year compliance period, for instance, there would be three points at which the agency issues ERCs. After
a.
b.
The following are proposed required components of the eligibility application, as specified for these measures in the final EGs:
(1) The EPA proposes that the federal plan will require that providers must show that the generation they would be providing to the federal plan system for ERC issuance is only being credited in the federal plan, and will not be submitted for ERC issuance in any other rate-based crediting system in any other state. As discussed in section IV.C. of this preamble, we are proposing that states with rate-based emission standards plans that have eligibility and EM&V requirements compatible with the federal plan would have the opportunity to participate in the federal plan trading systems, and create a shared pool of creditable reductions, in which case credits approved by such states would be eligible for use by affected EGUs in the federal plan.
(2) The provider must show that the project is using an eligible RE or nuclear resource. Specific requirements are proposed in section IV.C of this preamble.
(3) The provider must show that the project has an EM&V plan that meets the federal plan requirements. Proposed requirements specific to the federal plan are proposed in section IV.D.8 of this preamble. As specified in section IV.D.8 of this preamble, we request comment on whether nuclear energy resources should be subject to the same EM&V requirements as RE resources, and if not, we request comment on the EM&V requirements to which nuclear energy resources should be subject.
(4) There are special conditions if the provider is located in a state with a mass-based plan. For eligible RE capacity, the provider can only be credited in a rate-based state or rate-based multi-state system if the provider can demonstrate that the generation was produced to meet electricity load in a state with a rate-based plan. The EPA is proposing that an RE provider can make this demonstration by providing documentation of a power purchase agreement or delivery contract from the rate-based state and show that the measure was treated as a generation resource used to serve regional load that included the rate-based state. For incremental nuclear capacity, no provider in a state with a mass-based plan can be eligible for ERC issuance in a rate-based state. This requirement and the justification for its inclusion is further discussed in section III.A of this preamble on Interstate Effects and also discussed in the Interstate Effects section of the final EGs (see sections VIII.K.1 and VIII.L). The EPA is proposing that there would be no other geographic limitation on the location of the providers of RE and incremental nuclear generation submitted for ERC issuance under the rate-based federal plan approach.
(5) This application must include an independent third-party verifier's review and approval of the eligibility requirements, as is reflected in EM&V requirements for the final guidelines, and specified as part of the proposed federal plan EM&V requirements in section IV.D.8 of this preamble.
We request comment on each criterion of the eligibility application described herein and in the proposed model rule, for each eligible resource. Specifically, we seek comment on the substantive content of the criteria, and we seek comment on the level of detail provided and whether more or less detail (and what detail) should be included in the final model rule.
The EPA is proposing that ERCs would be tracked in the ATCS. Additionally, the EPA is proposing that the agency would establish a complementary tracking system for the ERC issuance process. It would provide for transparent access to RE project and program eligibility applications and regulatory approvals as well as information on the activities of accredited third party verifiers (third party verifiers are further discussed in section IV.D.7 of this preamble), as well for the public to be able to generate reports based on this information.
The agency is proposing that the project eligibility applications would be accepted after the finalization of the federal plan and prior to the first compliance period, as soon as the agency is able to establish an application process, and that applications would be accepted on an annual basis. The agency requests comment on whether a quarterly or biannual application process is more appropriate. These applications would be accepted through the entirety of all compliance periods. The EPA will review and approve the project applications. It is proposed that the EPA
For the second step in the credit issuance application process, the EPA proposes that providers submit an M&V report to the EPA, or its designated agent, prior to the EPA's issuance of ERCs. This can only occur after the approval of a project application, the RE has been generated, and necessary EM&V has been completed.
The following are proposed required components of the M&V Report:
(1) Documentation of completed EM&V in accordance with the EM&V plan submitted by the RE or nuclear provider, including quantification of the MWh of generation to be credited and verification of their creation.
(2) Documentation that the generation has not been submitted for crediting under any other federal or state plan, including to another rate-based credit tracking system.
(3) Documentation that the MWh resulted from RE or incremental nuclear capacity eligible for crediting under the federal plan requirements and in accordance with final EGs. This documentation should note if the MWh are from an RE project located in a state with a mass-based plan, and show if the generation is approved to be eligible for ERC issuance under the federal plan. See above geographic eligibility discussion and section III.A of this preamble for specifics on the required demonstration for this type of RE generation. As discussed in that section, this option is proposed to not be available to incremental nuclear capacity located in a state with a mass-based plan.
(4) This application must include a verification report from an independent third-party verifier, submitted after the verifier's review and approval of the eligibility application, as is reflected in EM&V requirements for the final guidelines, and specified as part of proposed federal plan EM&V requirements described below and included in detail in the proposed model rule.
If the application meets these requirements, pursuant to review by the EPA or its designated agent, ERCs will be issued to the provider by the EPA through the ATCS. The specific steps of the process by which an eligible resource seeks ERCs, and by which an affected EGU may use ERCs in its compliance demonstration, are described in the proposed model rule. One of the steps requires the proponent to register for a general account in the EPA tracking system where the ERCs would be recorded. See 40 CFR 62.16515 for the requirements to establish a general account. While EPA is proposing to allow eligible resources to use a general account to receive any ERCs issued under this section, the EPA requests comment on extending the designated representative provisions in 40 CFR 62.16485 to eligible resources instead of the general account provisions. Requiring eligible resources to submit information similar to that collected in the certificate of representation in 40 CFR 62.16500 and to appoint a designated representative to act on behalf of all owners/operators for all projects requesting ERCs may improve the EM&V process by making the eligible resources more accountable.
Because it is critical to the integrity of an ERC that it represents the actual MWh of energy generated or saved that it purports to represent, and as required in the EGs for state plans, the federal plan and model rule include provisions to address error correction (
The agency is proposing that M&V reports will be accepted starting before the beginning of the first compliance period (January 1, 2022), through an application process the agency will establish and administer, and that applications will be accepted on an annual basis. These applications will be accepted through the entirety of all compliance periods. The EPA will review and approve M&V reports, and may designate an agent to coordinate and assist with M&V reports. The EPA is proposing that it will issue ERCs for a given year no later than 6 months after the end of the relevant year. This amount of time may be necessary to accommodate the ERC issuance process, including necessary EM&V. The overall proposed schedule for trading and true-up has been constructed to allow for this period of time for EM&V after the compliance period.
For purposes of the proposed rate-based federal plan, the EPA proposes to implement the CEIP on behalf of a state by issuing early action ERCs for eligible actions located in or benefitting that state that are implemented after September 6, 2018 and that generate zero-emitting MWh or reduce energy demand in 2020 and/or 2021.
• RE investments that generate metered MWh from any type of wind or solar resources; and
• Demand-side EE programs and measures implemented in low-income communities that result in quantified and verified electricity savings (MWh).
The EPA proposes the following framework to implement the CEIP in the rate-based federal plan. First, the EPA proposes to implement a mechanism for issuing early action ERCs for eligible RE projects that commence construction and eligeible EE projects that commence implementation after September 6, 2018 and that generate zero-emitting MWh or reduce end-use energy demand during 2020 and/or 2021. These projects must be located in or benefit the state on whose behalf the EPA is implementing the federal plan. The EPA proposes to design this mechanism in a manner that would have no impact on the aggregate emission performance of sources required to meet rate-based emission standards during the compliance periods. The EPA requests comment on the structure of this mechanism, which could include adjusting the stringency of the emission standards during the compliance periods to account for the issuance of early action ERCs for MWh
Second, the agency proposes to create an account of “matching” ERCs for each state participating in the CEIP—regardless of whether a state is implementing a state plan or the agency is implementing a federal plan on its behalf. This distribution would reflect each state's pro rata share—based on the amount of the reductions from 2012 levels the affected EGUs in the state are required to achieve relative to those in the other participating states—of a federal pool of additional ERCs, which would be limited to the equivalent of 300 million short tons of CO
Following the effective date of a rate-based federal plan for a state, the agency will create an account of matching ERCs for the state that reflects the pro rata share of the 300 million short ton CO
The EPA has determined in the final EGs that independent verification requirements are necessary to ensure the integrity of any rate-based emission trading program, given the types of eligible measures that may generate ERCs and the broad geographic locations in which those measures may occur. Inclusion of an independent verification component provides technical support for the EPA in the context of the proposed federal plan, and the states in the context of their plans, to ensure that eligibility applications and monitoring and verification reports are appropriately reviewed prior to issuance of ERCs. Inclusion of an independent verification component is also consistent with similar approaches required by state PUCs for the review of demand-side EE program results and GHG offset provisions included in state GHG emission budget trading programs.
The remainder of this section and the related language in the proposed model rule provide the proposed basis by which the EPA intends to evaluate the independence of the verifiers that it uses to provide verification reports pursuant to the federal plan. The qualifications described here and in the model rule would be presumptively approveable in the context of a state plan.
As a starting point, an independent verifier must have the necessary technical qualifications to provide verification services for the subject in question, as well as fulfill certain codes of conduct in providing verification services. Only verifiers approved or “accredited” by the EPA may provide verification services related to ERC issuance for the federal plan, in the same way that only verifiers approved by a state may be eligible to perform verification services pursuant to a state plan.
In addition, verifiers must have sufficient knowledge of the rate-based emission trading program rules, technical expertise, and knowledge of auditing, accounting, and information management practices, in order to perform verifcation services related to the Clean Power Plan. Accredited verifiers must be independent. Accredited verifiers may not provide verification services for any eligible resource for which they have a financial, management, or other interest.
This section identifies and discusses the EM&V approaches used to quantify and verify MWh from RE, demand-side EE, and other eligible measures used to generate ERCs or otherwise adjust an emission rate.
Only a subset of the potentially creditable ERC resources discussed in this section are actually being proposed as part of the federal plan. The remainder, and their associated requirements, are provided as part of the proposed model trading rule. Thus, all provisions of this subsection relating to such resources are presented only for the purpose of comment in the context of the federal plan, but are actually proposed for inclusion in the model trading rule. The ERC resources proposed in the federal plan must meet the following criteria: (1) They are in the following categories of measures: On-shore wind, solar, geothermal power, hydropower, or new nuclear units and capacity uprates at existing nuclear units; and (2) they can provide quantified generation data from a revenue quality meter. The language pertaining to all other measures (
Additionally, with respect to EM&V, the EPA describes certain established industry best-practice methods, procedures, and approaches that would be presumptively approvable if included in state plans. States wishing to adopt the model rule must submit these methods, procedures, and approaches as specified, or may submit alternative EM&V that is functionally equivalent to the industry best-practices described as presumptively approvable.
As discussed in section IV.C.3 of this preamble, quantified and verified MWh of RE generation and other means of generating ERCs may be used to adjust a CO
a.
In addition, the EPA's proposed EM&V methods, procedures, and
Submittals. Applicable submittals under a rate-based emission trading program include eligibility applications (including EM&V plans), monitoring and verification reports, and verification reports. These submittals are described in section VIII.K.3.b of the final EGs preamble and in this model rule and federal plan. At the initiation of a program or project, ERC providers develop and submit to the state or the EPA, respectively, an EM&V plan that documents how requirements for quantification and verification will be addressed as EM&V is performed over the program or project period. After implementation has occurred, the ERC provider must submit periodic M&V reports to document and describe how each of the requirements were applied. These reports must also specify the resulting MWh savings or generation values, as determined on a retrospective (ex-post) or real-time basis. MWh values may not be determined using projections or other ex-ante quantification approaches.
Each EM&V plan submitted in support of an eligibility application must identify the eligible resource covered by the plan, and provide specific EM&V criteria that specify the manner in which the energy generated or saved by the eligible resource will be quantified, monitored and verified. The manner of quantification, monitoring and verification must meet the criteria outlined below and included in the proposed model rule, as applicable to the specific eligible resource. We request broad comment on each criteria specified below and in the proposed model rule, for each eligible resource. Specifically, we seek comment on the substantive content of the criteria, and we seek comment on the level of detail provided and whether more or less detail (and what detail) should be included in the final model rule, and whether the criteria should differ for each eligible resource.
Each M&V report submitted in support of the issuance of ERCs to a specific eligible resource must include specific criteria described here and in the proposed model rule. For the first M&V report submitted, a key component is documentation that the electricity-generating resources or electricity-saving measures were installed or implemented consistent with the description in the approved eligibility application. Each following M&V report must then identify the time period covered by the M&V report, describe how the methods specified in the EM&V plan were applied during the reporting period, and document the quantity (in MWh) of energy generation and/or electricity savings quantified and verified for the period covered by the M&V report. Any change in the energy generation or savings capability of the eligible resource during the period covered by the M&V report must also be included in the M&V report, along with the date on which the change occurred, and information sufficient to demonstrate whether the eligible resource continued to meet all eligibility requirements during the period covered by the M&V report. Any change should also be specified in the report. The EPA requests broad comment on each of these criteria, as described here and in the proposed model rule. Specifically, we seek comment on the substantive content of the criteria, and we seek comment on the level of detail provided and whether more or less detail (and what detail) should be included in the final model rule, and whether the criteria should differ for each eligible resource.
Each verification report submitted by an independent verifier in support of the issuance of ERCs to a specific eligible resource must address the criteria described here and in the proposed rule text. Each verification report must set forth the findings of the verifier, based on an assessment of all relevant requirements, information and data, including an assessment of any material misstatements or data discrepancies. Any verification report included as part of an eligibility application must further describe the review conducted by the verifier and verify the following: The eligibility of the resource to be issued ERCs; that the eligible resource exists and has been, or will be, generating energy or saving electricity in the manner required; that the EM&V plan meets its requirements; and any other information required or that the verifier finds, in its professional opinion, is necessary to assess the accuracy of the subject of the verification report. Each verification report included as part of a M&V report must also describe the review conducted by the verifier and verify the following: The adequacy and validity of the information and data submitted to quantify eligible MWh of electric generation or electricity savings during the period covered by the report, as well as all supporting information and data identified in the EM&V plan and M&V report; evaluate whether all generation or savings data are within a technically feasible range for that specific eligible resource (determined through a quality assurance and quality control check of the data); that the M&V report meets its requirements; and any other information required or that the verifier finds, in its professional opinion, is necessary to assess the accuracy of the subject of the verification report. The EPA requests broad comment on each of these criteria, as described here and in the proposed model rule. Specifically, we seek comment on the substantive content of the criteria, and we seek comment on the level of detail provided and whether more or less detail (and what detail) should be included in the final model rule, and whether the criteria should differ for each eligible resource.
For demand-side EE, all EM&V plans that are developed for purposes of adjusting an emission rate under this proposed rule are intended to leverage and closely resemble the plans already in routine use for a wide range of publicly or rate-payer funded EE programs and energy service company (ESCO) projects. For RE, EM&V plans similarly leverage resources and approaches to MWh tracking for RE that are broadly applied in the state and regions. The existing reports and documentation from existing tracking systems may serve as the substantive basis for a monitoring and verification report for RE.
b.
The primary metric for all RE is electricity generation, in units of MWh. Measured output must be derived either from: (1) A revenue quality meter that meets the applicable ANSI C-12 standard or equivalent, which is the typical requirement for settlements with RTO and other control-area operators; or (2) For customer-sited generators that are interconnected behind the customer meter, measurement at the AC output of an inverter, adjusted to reflect the energy delivered into either the transmission or distribution grid at the generator bus bar. Further, a RE generating facility of 10 Kilowatt capacity or less may estimate the facility's output if the state where it is located explicitly allows estimates to be used and provides rules for when it will be allowed. In the latter case, calculations of system output must be based on the RE unit's capacity, estimated capacity factors, and an assessment of the local conditions that affect generation levels. All such input parameters and assumptions must be clearly described and documented. For RE units that are managed by regional transmission operators or other control area operators, metered generation data should be electronically collected by the control area's energy management system, verified through an energy accounting or settlements process, and reported by the control area operator to the REC registry at least monthly. The EPA requests comment on this proposed requirement for quantifying RE generation for the purpose of ERC issuance.
For RE units that do not go through a control area settlements process, metered data may be read and transmitted to the ERC registry by an independent third party, or may be self-reported. Third-party and self-reported generation data must be reported on an annual basis. All such data must be verified for reasonableness by the agency, the state, or the REC registry.
For reporting purposes, RE generation may be aggregated from multiple generators into a single MWh value for the group, provided the following requirements are met: Each RE unit is uniquely identified in the federal tracking system, the nameplate capacity of each RE unit is less than 150 Kilowatt, the aggregated RE units collectively have nameplate generating capacities less than 1.0 MW, the units aggregated are located in the same state, the RE units being aggregated utilize the same technology/fuel type, and the RE unit's generation data are based on the same metering or the same generation estimating software or algorithms. The EPA requests comment on how existing reporting systems can play a role in meeting EM&V requirements under the federal plan and model rule, particularly, in assuring that each MWh of RE generation is uniquely identified and recorded to avoid double counting.
An additional consideration regarding distributed RE units that directly serve on-site end-use electricity loads is that avoided transmission and distribution (T&D) system losses can be quantified, as is commonly practiced with demand-side EE. If such T&D losses are quantified, the requirements for demand-side EE would be applicable.
The EPA requests comment on all metering, measurement, verification, and other requirements proposed in this subsection, including the appropriateness of their use for each type of RE resource (including the relevant size and distribution of such resource) that qualifies for issuance of ERCs for use for compliance.
For RE resources with a nameplate capacity of 10 Kilowatt or more and for RE resources with a nameplate capacity of less than 10 Kilowatt for which metered data are available, we request comment on the appropriateness of the requirement to use a revenue quality meter for monitoring generation, and we request comment on the definition of revenue quality meter. We request comment on the appropriateness of other types of meters for monitoring generation. We request comment on whether 10 Kilowatt is the appropriate threshold, under which an eligible resource can be issued ERCs for generation based on data other than metered generation, and if not, what would be the appropriate threshold.
For RE resources of all sizes and means of monitoring, we request comment on the appropriate requirements for allowing generation data to be aggregated, including comment on the provisions in the proposed model rule and any alternatives to them. We request comment on whether all of the generating units have the same essential generation characteristics, in order for their data to be aggregated, and if so, what is the appropriate definition of “essential generation characteristics” (
For non-metered units of less than 10 Kilowatt, we request comment on whether the final model rule should specify the specific estimating software or algorithms by which generation data should be measured, and if so, we request broad comment on the appropriate estimating software or algorithms and the appropriate characteristics for such estimating software or algorithms.
We request comment on any other requirements that should be included in the final model rule regarding EM&V of RE resources.
For all energy generating resources (such as RE, but also including applicable resources requiring EM&V described below), we request comment on the appropriate place of measurement of the generation, including comment on whether measurement should be at the bus bar or at a different location (or in the case of meters on units of less than 10 Kilowatt, at the AC output of the inverter or elsewhere), whether measurement should be before or after parasitic load (and how to separate out parasitic load). In addition, for all energy generating resources, we request comment on whether generation data should go through a control area settlement process prior to issuance of ERCs, and if so, what level of specificity with respect to that process we should include in the final model rule. If not, or if the unit does not go through a control area settlement process, we request comment on how the data collection should be specified in the final model rule. Finally, we request comment on the frequency with which data should be collected, for all energy generating resources, of all sizes.
c.
The EPA requests comment on all metering, measurement, verification, and other requirements in this subsection, including the appropriateness of their use for each type of nuclear energy resource (including the relevant size and distribution of such resource) that qualifies for issuance of ERCs for use in Clean Power Plan compliance. We request comment on whether nuclear energy resources should be subject to the same EM&V requirements as RE resources, and if not, we request
d.
In order to determine the incremental CO
Non-affected CHP facilities
The EPA requests comment on all metering, measurement, verification, and other requirements included in this subsection with respect to CHP, including the appropriateness of their use for CHP (including with respect to the size of the CHP resource). We request comment on whether a CHP unit should be subject to the same EM&V requirements as RE resources, and we request comment on any additional EM&V requirements to which CHP units should be subject. Specifically, we request comment on specifying in the final model rule that if a CHP unit has an electric generating capacity greater than 25 MW, its EM&V plan must specify that it will meet the requirements that apply to an affected EGU under 40 CFR 62.16540. We also request comment on specifying in the final model rule that if a CHP unit has an electric generating capacity less than or equal to 25 MW, the EM&V plan must specify that it will meet the low mass emission unit CO
e.
The EPA requests comment on all metering, measurement, verification, and other requirements included in this subsection with respect to biomass, including the appropriateness of their use for qualified biomass. We request broad comment on the types of qualified biomass feedstocks that should be specified in the final model rule, if any. We request comment on the methods that we should specify in the final model rule for the measurement of the associated biogenic CO
f.
As discussed in the final EGs (see section VIII.K.1 of the final EGs), only the portion of electric generation at a waste-to-energy facility that is due to the biogenic content of the MSW may be used to generate ERCs or counted by a state towards its achievement of its obligations pursuant to this regulation.
The EPA requests comment on all metering, measurement, verification, and other requirements included in this subsection with respect to waste-to-energy, including the appropriateness of their use for waste-to-energy. We request comment on whether a waste-to-energy resource should be subject to the same EM&V as RE resources, and we request comment on any additional EM&V requirements to which waste-to-energy resources should be subject, including comment on any specific methods for determining the specific portion of the total net energy output from the resource that is related to the biogenic portion of the waste that the EPA should include in the final model rule.
g.
For all demand-side EE used to generate ERCs, the EPA is proposing that the metric is MWh of electricity savings, which must be quantified on an ex-post or real-time basis and defined as a reduction in facility- or premises-level electricity consumption due to an EE program, project, or measure.
Based on public input and assessments of industry best-practice protocols and procedures, the EPA is proposing that it is presumptively approvable to quantify EE savings as the difference between actual metered electricity usage after an EE program, project, or measure is implemented, and a “common practice baseline” (CPB). A
The applicable CPB depends on a number of factors, such as characteristics of the EE program, project, or measure, the mechanism by which electricity customers are engaged, local consumer and market characteristics, and the applicable building energy codes and product standards (C&S), including the C&S compliance rate. Examples of appropriate CPBs to apply in specific circumstances, which may be presumptively approvable, can be found in the EPA's EM&V guidance. EE providers must document the selected CPB in their EM&V plans, along with clear documentation and discussion of the rationale, applicability, and relevant data sources, protocols, and other supporting information. Monitoring and verification reports must refer to the EM&V plan and confirm that the CPB was appropriately applied.
This section proposes criteria that are presumptively approvable for the general types of EM&V methods that EE providers may use to quantify the MWh savings from demand-side EE programs, projects, and measures. During the Clean Power Plan EG's public comment period, the EPA received input indicating that state PUCs typically allow utilities and other EE providers to use a range of EM&V methods that reflect applicable circumstances and on-the-ground conditions (versus mandating which methods must be used in a particular situation). Consistent with this approach, the EPA is proposing to offer flexibility for EE providers to select from three broad categories of EM&V methods to determine savings.
These categories include project-based M&V, deemed savings, and comparison group approaches such as randomized control trials (RCT). Regardless of the approach selected, the EPA is proposing that annual savings values must be quantified using these EM&V methods at specified time intervals (in years) on a recurring basis over the effective useful life of the EE project or measure in order to ensure accurate and reliable savings values. To be presumptivey approable, the EPA is proposing that EE providers must apply the above methods at a minimum of 4-year intervals for building energy codes and product standards; every 1, 2, or 3 years for publicly- or utility-administered EE programs, depending on the program type, magnitude of savings, and experience with the program; and annually for large individual commercial and industrial projects, unless the EE provider can credibly demonstrate why this is not possible and how the accuracy and reliability of savings values will be maintained. The EPA is further proposing that, to be presumptively approvable, the selected method, associated assumptions, and data sources must be identified and described in EM&V plans.
For comparison group approaches, the EPA is propsing that states and EE providers can refer to the EPA's draft EM&V guidance for a discussion of industry best-practice protocols and guidelines. Where feasible, the EPA is proposing to encourage the use of RCT methods, which determine savings on the basis of energy consumption differences between a treatment group and a comparison group, and therefore increase the reliability of results.
As noted above, an alternative to comparison group methods is the use of deemed savings values, which establish pre-determined annual electricity savings values for specific EE measures. The EPA is proposing that the use of deemed savings values would be presumptively approvable if those values (a) are documented in a publicly available database (also known as a Technical Reference Manual (TRM)) that is accessible on a public Web site, or is otherwise readily accessible; (b) specify the conditions for which each deemed value can be applied, including but not limited to climate zone, building type, and EE implementation mechanism; and (c) are updated at a minimum of every 3 years to reflect the per-measure MWh savings documented in ex-post EM&V studies that apply M&V or comparison group methods.
For M&V methods to be presumptively approvable, the EPA is proposing is that industry best-practice protocols and/or guidelines must be followed. Examples of acceptable best-practice protocols and guidelines are provided in the EPA's EM&V guidance. EE providers can consult the EM&V guidance to assess the applicability of these technical resources to the EE programs and projects generating savings, and must document how one or more best-practice protocols or guidelines will be appropriately applied in EM&V plans (along with clear documentation and discussion of the rationale, applicability, and relevant data sources, and other supporting information). The EPA is also proposing that monitoring and verification reports must refer to the EM&V plan and confirm that the relevant M&V protocol or guideline was properly applied.
Regardless of the approach used to quantify and verify MWh savings, the EPA is proposing that EM&V plans must describe how they will address the following provisions:
• How major changes in independent variable conditions (weather, occupancy, production rates, etc.) that affect energy consumption and savings estimates will be accounted for. The EPA is proposing that the effects of these changes must be calculated using industry best-practices such as real-time conditions or normalized conditions that are reasonably expected to occur throughout the lifetime of the EE project or measure.
• How the initial installation of EE will be verified for EE program categories that involve the installation of identifiable measures (
• How avoided T&D system losses
• How the duration of EE program or project electricity savings will be determined. This must be determined using industry best-practice protocols and procedures involving annual verification assessments, industry-standard persistence studies, deemed estimates of effective useful life (EUL), or a combination of all three.
• How the accuracy and reliability of quantifying MWh savings values will be assessed, and the rigor
• How double counting will be avoided through the use of tracking and accounting procedures to ensure that the same MWh of electricity savings is not claimed more than one time (for example, two EGUs claiming savings from the same lighting retrofit). The types of double counting that may arise are discussed in the EPA's draft EM&V guidance.
In the Clean Power Plan EG's public comments, the EPA heard that EM&V protocols for demand-side EE are currently in wide use, and that they should be continued and encouraged. The agency agrees with this observation and is therefore proposing the application of industry best-practice protocols and procedures for demand-side EE. In particular, the EPA is proposing that, to be presumptively approvable, EM&V plans must specify the use of best-practice protocols and procedures, and must also include a clear description and documentation of how the relevant protocols and procedures will be applied. EM&V reports must include documentation of how such protocols and procedures were actually applied. EE providers can refer to the EPA's EM&V guidance document for information about protocols that are considered “industry best-practice protocols and procedures.”
There has been stakeholder interest expressed through the Clean Power Plan EGs rulemaking process in allowing states to issue ERCs for quantified and verified MWh savings from DS-EE under state plans. Consistent with these perspectives, the EPA is proposing that any demand-side EE program, project, or measure that results in MWh savings may be potentially eligible to generate ERCs, including under this proposed model trading rule, provided that they meet the presumptively approvable provisions for eligibility described in section IV.C.3 of this preamble, and that supporting EM&V is rigorous, transparent, credible, complete and fulfills the requirements provided in the EGs and the state plan. Examples of potentially eligible demand-side EE program and project types include:
• Publicly or utility-administered EE programs, including those implemented in low-income residences and facilities.
• Project-based EE evaluated site-by-site, for example those implemented by ESCOs at commercial buildings and industrial facilities.
• State and local government building energy code and compliance programs.
• State and local government incremental product energy standards.
The EPA's EM&V guidance contains supplemental information about applicable best-practice protocols, methods, and other key considerations for quantifying and verifying savings from the above-listed EE activities in an accurate and reliable manner. The agency also recognizes that the programs and policies listed above will evolve and change over the rule period, as new technologies emerge and efficiency improves. The agency also expects that new EE program types will emerge and expand throughout the rule period, and that MWh savings resulting from any such programs can similarly be considered if they meet the requirements of the EGs.
We request broad comment on each EE EM&V criterion described herein and in the proposed rule text, for each type of EE activity, project, program, or measure. Specifically, we seek comment on the substantive content of the criteria, and we seek comment on the level of detail provided regarding these criteria and whether more or less detail (and what detail) should be included in the final model rule. In addition, we seek comment on whether some of the EE EM&V criteria (and if so, which criteria) included in the draft guidance document released simultaneously with this proposed rulemaking should instead be included in the final model rule, instead of in guidance. Similarly, we seek comment on whether some of the EE EM&V criteria (and if so, which criteria) included in the proposed model rule should instead be addressed in the final EM&V guidance. More generally, we seek comment on what EE criteria the EPA should described in guidance versus what criteria the EPA should specify in the final model rule, whether or not those criteria are already included in the draft guidance or proposed model rule.
We request broad comment on the appropriate EE EM&V criteria for quantifying the electricity savings from every type of EE program, project, or measure. We request broad comment on what constitute EE best-practice protocols and procedures for every type of EE program, project, or measure.
We request broad comment on whether, when, and how common practice baselines should and should not be used in calculating electricity savings from EE activities, projects, programs, and measures, including comment on which common practice baselines should be used in which circumstances. We also request comment on whether some alternative metric should be used in lieu of the common practice baseline and, if so, what that metric should be.
We request broad comment on the appropriateness of quantifying electricity savings by applying one or more of the following methods and comment on all aspects of each method: Project-based measurement and verification (PB-MV), comparison group approaches, or deemed savings. We take further comment on circumstances in which it is appropriate (or inappropriate) to use each of these methods, including when it is appropriate to use RCT and quasi-experimental methods, and the circumstances in which they can be encouraged and applied in practice (
If deemed savings are to be used in quantifying electricity savings from an EE program, project, or measure, we request comment on the appropriate characteristics and presumptively approvable provisions for their use in generating qualifying ERCs, including the basis and frequency for their determination, and the appropriateness of their application to particular EE programs, projects or measures in particular states or regions. We further request comment on the presumptively approvable provision for public access and input to the development of the technical reference manuals (TRMs) used to house the applicable deemed savings values.
We request comment on the minimum and maximum intervals (in years) over which electricity savings must be quantified, including those time intervals specified in the proposed model rule, and we request comment on any factors that must be taken into consideration when determining the appropriate time interval for specific EE programs, projects, or measures.
Because many states have different EE programs in place today, and we would expect them to leverage these programs if they incorporated EE into a rate-based trading scheme with ERCs, it is theoretically possible that an ERC could be issued in one state that would not have been issued in another, even if both states have rate-based programs in place that meet all of the EGs. The EPA requests comment on what criteria it should include in the final model rule, and what level of details with respect to those criteria that it should include, in order to ensure that an ERC issued for an EE program, project, or measure in one state reflects the same MWh of energy or electricity saved in another state. We further request comment on whether there are provisions that the EPA should include in the final model rule that would prevent an entity seeking to be issued an ERC (whether from EE or energy generation) from forum shopping, in an effort to find a state with standards for ERC issuance that it deems more lenient or less burdensome than those in another state.
We request comment on how to appropriately consider factors that affect energy savings in the quantification and verification process, including those identified in the proposed model rule, and we request comment on whether these factors should be addressed in every plan or just certain types of plans. Such factors may include the effect of changes in independent factors, effective useful life (and its basis), and interactive effects of EE programs, projects, and measures.
We request comment on the circumstances and frequency in which savings verification must occur to ensure that EE measures have been installed, are functioning, and have the potential to save energy.
We request comment on the appropriate steps for avoiding double counting, and how such steps should be documented in an EM&V plan. In particular, we request comment on the circumstances and conditions in which double counting is most likely to occur (including those identified in this section), and the presumptively approvable provisions that must be adopted in state plans for avoiding and mitigating double counting.
We request comment on the appropriate means by which an EM&V plan can ensure the accuracy and reliability of electricity savings estimates, including the necessary rigor of the methods selected to evaluate the electricity savings, the methods used to control all relevant types of bias and to minimize the potential for systematic and random error, and the potential effects of such bias and error. We further request comment on the presumptively approvable provision that samples taken to quantify EE program savings must achieve 90/10 confidence and precision.
We request comment on the presumptively approvable approach to quantifying the electricity savings that result from avoiding a transmission and distribution system loss, including the provisions in the proposed model rule, which specify that each EM&V plan must quantify the transmission and distribution loss based on the lesser of 6 percent of the site-level electricity consumption measured at the end use meter or the statewide annual average transmission and distribution loss rate (expressed as a percentage) from the most recent year that is published in the U.S. EIA State Electricity Profile. We request comment on the appropriateness of including a restriction in the final model rule that no other transmission and distribution loss factors may be used in calculating the electricity savings.
We request comment on any additional criteria that we should include in the final model rule regarding EE EM&V.
h.
The EPA agrees that in conjunction with other EM&V measures discussed in this section, and in the context of the model trading rules although this is not an aspect needed for presumptive approvability, states are encouraged to include in their plan a description of how states will ensure that workers installing demand side EE and RE projects, or other measures intended to reduce CO
• Develops a training or competency based program aligned with a job task analysis and/or certification scheme;
• Engages with subject matter experts in the development of the job task analysis and/or certification schemes that represent appropriate qualifications, categories of the jobs, and levels of experience;
• Has clearly documented the process used to develop the job task analysis and/or certification schemes, covering such elements as the job description, knowledge, skills, and abilities;
• Has pursued third-party accreditation aligned with consensus-based standards, for example ISO/IEC 17024 or IREC 14732.
Examples of such entities include: Parties aligned with the DOE's Better Building Workforce Guidelines and validated by a third party accrediting body recognized by DOE; or parties aligned with an apprenticeship program that is registered with the federal DOL, Office of Apprenticeship; or parties aligned with a state apprenticeship program approved by the DOL, or by another skill certification validated by a third party accrediting body. Entities such as these can help to substantiate the authenticity of emission reductions due to demand-side EE and RE and other carbon emission reduction measures.
All affected EGUs that may be subject to this proposed federal plan would be required to be a part of the ATCS that
Non-EGU ERC generating sources are required to submit generation data annually (see section IV.C.3 of this preamble for a comprehensive discussion of non-EGU ERC generating sources). The data must follow the EM&V procedures delineated in section IV.D.8 of this preamble. Because of the required rigor of the EM&V process, the EPA provides a time frame of January 1 to June 1 of the year that follows the data's inception to complete all EM&V processes (
The process for transferring ERCs from one account to another is quite simple. A transfer would be submitted providing, in a format prescribed by the agency, the account numbers of the accounts involved, the serial numbers of the ERCs involved, and the name and signature of the transferring authorized account representative or alternate. If the transfer form containing all the required information were submitted to the EPA and, when the Administrator attempted to record the transfer, the transferor account included the ERCs identified in the form, the Administrator would record the transfer by moving the ERCs from the transferor account to the transferee account within 5 business days of the receipt of the transfer form.
Once the compliance period has ended, affected EGUs would have a window of opportunity to evaluate their reported emissions and obtain any ERCs that they might need to cover their emissions during the compliance period. The agency proposes to require sources to demonstrate compliance,
The EPA will use the submitted generation, CO
If an affected EGU fails to hold sufficient ERCs to comply with its emission standard then, upon notification of the deficiency, the owners and operators of the affected EGU must provide, for deduction by the Administrator, two ERCs as soon as available for every ERC that the owners and operators failed to hold as required to cover emissions, in addition to the ERCs owed for compliance in that next period. The owed ERCs will be deducted from the EGU's compliance account as soon as they are available in this account; the Administrator will not wait until the next true-up date to make this deduction. The two ERCs owed for each ERC needed for compliance but not supplied is in addition to any other recourse provided in sections 113(a)-(h) or section 304 of the CAA. This requirement to surrender two times the ERCs needed to make up the shortfall for the prior period is an ongoing obligation until compliance is achieved, and there is an ongoing obligation to comply in the current period. Failure to surrender these replacement ERCs is an additional violation that may be subject to federal enforcement. The EPA solicits comment on sources owing two ERCs to make up for each insufficient ERC in previous compliance periods and whether two for one is the proper make-up rate or whether there should be a stricter or a more lenient ratio.
The EPA believes that it is important to include a requirement for an automatic deduction of ERCs. The deduction of one ERC per ERC that the owners and operators failed to hold would offset this failure. The deduction of another ERC per ERC that the owners and operators failed to hold provides a strong incentive for compliance with the ERC-holding requirement by ensuring that non-compliance would be a significantly more expensive option than compliance. This is consistent with other existing trading programs.
These sections also would provide that the Administrator could, at his or her discretion and on his or her own motion and consistent with existing federal trading programs, correct any type of error that he or she finds in an account in the ATCS. In addition, the Administrator could review any submission under the rate-based trading program, make adjustments to the information in the submission, and deduct or transfer ERCs based on such adjusted information. These provisions are a standard part of other trading programs administered by the EPA including the ARP and the CSAPR (
The EPA is proposing to allow unlimited banking of ERCs within and between the interim and final compliance periods. This means that if an affected EGU has more ERCs than are necessary during true-up, it may save (
ERC “borrowing” is a flexibility that the EPA is not proposing, but is soliciting comment on. ERC borrowing is the concept that an affected EGU may use an ERC that the EGU will acquire in a future compliance period to meet its current compliance obligations. The EPA requests comment on a methodology that would allow ERC borrowing while maintaining the integrity of the compliance obligations. The EPA also has reservations concerning this concept due to the fact that future ERC generation is not guaranteed.
The EPA would require that emission and generation data be reported to the EPA quarterly starting on April 30, 2022, and continuing every 3 months thereafter (
The EPA also requests comment on requiring monitoring and reporting of CO
The EPA proposes that all affected EGUs within states that are covered by the federal plan, if a rate-based federal plan is finalized for two or more states, would be allowed to trade with one another since there will be an assured commonality in the ERC currency and criteria surrounding the trading program. In addition, the EPA proposes, consistent with the provision for “ready-for-interstate-trading” plans in the EGs, that affected EGUs located in states with approved ready-for-interstate-trading state plans using the subcategorized uniform rate standards, and a common credit currency (
Rate-based EGUs subject to the federal plan and rate-based EGUs in ready-for-interstate-trading state plans will be able to trade ERCs seamlessly across jurisdictional borders because of the assurances of being presumptively approvable. Ready-for-interstate-trading states must submit information that lists all affected EGUs and the EGU type to the Administrator to be able to trade within the federal trading program. To be able to trade in the federal trading program an affected EGU that is subject to a ready-for-interstate-trading state plan must: (1) Certify and authorize a designated representative per section IV.D.1 of this preamble; and (2) register a general account in the federal trading program, ATCS, in order to have a means of transferring ERCs with entities operating in the federal trading program. An affected EGU under a state plan will not register a compliance account in the federal system because it will not be demonstrating compliance under the federal plan. Compliance will be achieved in the affected EGU's corresponding state plan. Affected EGUs under a state plan have the ability to acquire ERCs through the federal trading program. These ERCs will be stored in the EGU's general account in the federal trading program. To use these ERCs for compliance purposes, the ERCs must be transferred to the EGU's compliance account in the state's program. The EPA proposes to provide software to states to maintain a state's compliance and tracking program. A state's program will have the capability to interact with the federal trading program and software, ATCS, for transferring ERCs if the state is ready-for-interstate-trading. A state's program can be tailored to meet its needs while still providing a platform for a state to be transferring ERCs between the state's system and the federal trading program. ERCs can flow between a state system and the federal trading program bilaterally. The EPA acknowledges that states may have additional criteria for generating ERCs that are not outlined as part of the federal plan, but because the EPA will have vetted these criteria through a state plan approval these ERCs will be able to be traded within the federal trading program.
The EPA proposes that a rate-based trading federal plan may be replaced by a state plan for a future compliance period. The EPA is proposing that a state must transition to a state plan at the conclusion of a federal plan compliance period. The EPA requests comment on whether there are reasons that a state should be allowed to transition from a federal plan to a state plan in the middle of a compliance period and if so what requirements should be put in place to do so while ensuring the integrity of both the federal plan and the state plan and while enabling the affected EGUs covered by the plans to understand and meet their compliance requirements. If a state subject to the federal plan transitions to a state plan, any affected EGU impacted by the change remains responsible for meeting any outstanding obligations under the federal plan. To make the transition to a state plan, a state must have an approved state plan as laid out in sections VIII.D and VIII.E of the final EGs.
In addition to the rate-based implementation approach discussed above, the EPA is proposing a mass-based implementation approach for the federal plan. As with the rate-based approach, this proposed federal plan is also a proposed model trading rule that states can adopt. The mass-based approach that the agency proposes to implement is a mass-based trading program (
A mass-based trading program establishes an “aggregate emissions limit” that specifies the maximum amount of emissions authorized from affected EGUs included in the program, and creates allowances that authorize a specific quantity of emissions. The total number of allowances created are equal to, and constitute, the emissions budget or the aggregated emissions limit expressed in terms of short tons of emissions. The EPA is proposing that allowances be issued in short tons for the federal plan.
Each facility with affected EGUs in the program must surrender allowances equal in number to the quantity of the emissions of its affected EGUs during the compliance period. A facility with affected EGUs may buy allowances from, or transfer or sell allowances to, other affected EGUs or other entities that participate in the market. A mass-based trading program provides sources with great flexibility in choosing compliance strategies.
In the proposed mass-based trading program for the federal plan, the aggregate emissions limit for a state is its statewide mass-based emission goal (or “mass goal”) as finalized in the Clean Power Plan EGs. The proposed approach to linking states for interstate allowance trading is detailed in section III.A.1 of this preamble; in an interstate trading program the aggregate emissions limit is the sum of the mass goals for the covered states.
The EPA believes that a broad trading region provides greater opportunities for cost-effective implementation of controls compared to a smaller region. Therefore, the agency proposes that an affected EGU in any state covered by the proposed mass-based trading federal plan may use for compliance an allowance distributed in any other state covered by the mass-based trading federal plan. The EPA also proposes to provide for allowance trading between affected EGUs and other entities in states with approved mass-based-trading state plans that meet the conditions specified in section III.A.1 of this preamble, above, and affected EGUs and other entities in any state covered by the federal plan mass-based trading program.
A mass-based trading program can provide environmental certainty at lower cost than other policy mechanisms, because it assures the specified emissions outcome while maximizing compliance flexibility available to individual affected EGUs. Further, allowance banking in such a program creates an incentive to make reductions earlier than required. Mass-based trading programs are relatively
In the proposed mass-based trading program federal plans, the emissions limits in each state would be the mass goals that the EPA promulgated in the Clean Power Plan EGs (if there is interstate trading then the sum of the mass goals for the states in the trading program would constitute the aggregate emissions limit). The total amount of allowances distributed in each state for each year would sum to the state's mass goal for that year. As detailed in section V.E of this preamble, the EPA is proposing that a state covered by the federal plan can determine its own approach to distribute allowances, and believes that state allocation has important merits. The EPA would distribute allowances in a state if the state does not choose to do so, as detailed below.
Each allowance would authorize the emission of one short ton of CO
After each compliance period, an affected EGU would surrender for compliance an amount of allowances equal to its emissions during the course of the compliance period. See section V.C of this preamble for the proposed length of the multi-year compliance periods. Allowances could be transferred, bought, sold, or banked (carried over for future use) and any party could participate in the allowance market. The EPA is not proposing allowance “borrowing” (
The EPA also proposes that a state may choose to replace the federal plan allowance-distribution provisions with its own allowance-distribution provisions (
This proposed requirement to hold and surrender allowances equal to emissions for each compliance period would apply to all reported emissions from a facility's affected EGUs including any emissions from co-fired biomass if biomass is included as an eligible measure. Section IV.C.3 of this preamble discusses an approach on which the EPA requests comment on the inclusion of biomass as an eligible measure and on a proposed option where the agency would identify qualified biomass feedstocks (
In the Clean Power Plan EGs the EPA established statewide mass-based emission goals (“mass goals”) for all states that are equivalent to the rate-based goals. As discussed in section V.C of this preamble, below, the EPA proposes to implement the mass-based trading program with multi-year compliance periods that are consistent with the compliance timing provisions in the Clean Power Plan EGs,
The EPA proposes to evaluate compliance (
The compliance periods in the proposed mass-based trading program would be the same as promulgated in the Clean Power Plan EGs,
Some existing GHG mass-based trading programs (
The EPA recognizes that the compliance periods provided for in this rulemaking are longer than those historically and typically specified in CAA rulemakings. As reflected in long-standing CAA precedent, “[t]he time over which [the compliance standards] extend should be as short term as possible and should generally not exceed one month.”
The EPA proposes that allowances may be banked for use in any future compliance period, with no restriction on the use of banked allowances, including from the Interim Period (2022 through 2029) into the Final Period (2030 and thereafter). The agency requests comment on the proposal to provide for unlimited allowance banking including the banking of Interim-Period allowances for use during the Final Period.
Allowance “borrowing” is a type of timing flexibility wherein allowances from a future compliance period may be “brought forward” and used for compliance in an earlier compliance period (thus reducing the amount of allowances available for the future period). The EPA notes that the proposed multi-year compliance periods inherently provide the flexibility to emit at relatively higher amounts in earlier years of a given compliance period by using allowances from future years within each compliance period (
Allowance borrowing across compliance periods would increase the complexity of the proposed mass-based trading program and reduce the flexibility for states to replace the federal plan with an approved state plan. First, in order for borrowing to occur, the EPA would have to make allowances from future compliance periods available early so that sources could use these future allowances in earlier compliance periods. The EPA proposes to record allowances in source accounts for one compliance period at a time in order to maximize the opportunities for a state to replace the federal plan (or replace the allowance-distribution provisions of the federal plan) with an approved state plan (or approved state allowance-distribution methodology). The EPA proposes to allow a state to replace the mass-based trading federal plan (or the federal plan allowance-distribution provisions) with a state plan (or state allowance-distribution methodology) for a compliance period for which the agency has not yet recorded allowances in source accounts. Recording allowances for multiple compliance periods at once—in order to make future-period allowances available for borrowing—would therefore limit these opportunities for states to take over implementation (or implementation of the allowance-distribution).
If allowance borrowing from a future compliance period were allowed, and the EPA provided the opportunity for a state to replace the federal plan for a year for which allowances had already been borrowed and retired for compliance in an earlier period, those borrowed allowances would constitute additional emissions beyond the levels specified in the Clean Power Plan EGs. In that event, the EPA would then need to address whether and how to remove allowances from circulation to prevent inflation of the allowable emissions at affected EGUs in the remaining states subject to the federal plans (to “repay” the borrowed allowances). To avoid disruption to sources already subject to the mass-based trading federal plan, the EPA is not proposing to allow allowance borrowing across compliance periods.
Although not proposing to provide for allowance borrowing across compliance periods, the agency requests comment on the potential inclusion of allowance borrowing in the proposed mass-based trading federal plans, including from how far into the future to allow allowances to be borrowed, how inclusion of borrowing would affect opportunities for states to take over implementation of the EGs (or implementation of the allowance-distribution provisions in the mass-based trading federal plan), how to address removing the extra allowances from circulation that would result if borrowed allowances originate in a state that subsequently withdraws from the mass-based trading program, and on other complexities that borrowing across compliance periods would introduce.
The agency proposes to require sources to demonstrate compliance,
The EPA proposes to evaluate compliance (
Establishing a mass-based trading program requires that policymakers establish an approach for the initial distribution of allowances, historically referred to as “allowance allocation.” The EPA believes that states may be well positioned to design their own allowance distribution approach because they can take into account a wide range of considerations and tailor decisions to the particular characteristics and preferences of their state. The EPA proposes that states have the flexibility to determine their own approach for distributing allowances in the federal plan, through a process that is detailed in section V.E of this preamble. The EPA believes that states should have the opportunity to make decisions about allowance distribution and that they may have additional flexibility on approaches, including allowance auctions. The EPA is also proposing an allocation approach that we intend to use in the event we implement the federal plan in a state that does not choose to determine its own allowance-distribution approach. The EPA requests comment on all of these, and any other, approaches to distribute allowances.
The initial allowance allocation approach that is based on historical data does not affect the environmental results of the program or generation patterns; regardless of the manner in which allowances are initially distributed, the finite total number of allowances limits allowable emissions across all affected EGUs. Allowance allocations also are not intended to prescribe or suggest any unit-level compliance requirements nor do they limit unit-level operational flexibility, because a mass-based trading program provides operators of affected EGUs with the flexibility to buy, sell, or bank allowances. Allowance allocation is simply a procedure by which allowances are distributed into the marketplace so that they may be available for affected EGUs to acquire as desired to authorize emissions under the program. However, because these allowances are finite in number and thus a limited resource, they have value, and as a result, initial allowance allocations may raise issues of equity among recipients.
Thus the agency recognizes that its choice of allocation methodology is important from the perspective of distributional effects, and the importance of selecting an approach that is fair and reasonable in light of this consideration and the overall purpose of CAA section 111 informs the agency's thinking in this proposal. We also invite comment on these considerations, and on any other factors or considerations which commenters believe should inform the allocation method.
The EPA believes that the most reasonable basis for an initial allowance allocation procedure is an approach that uses historical data reported by the affected EGUs subject to the requirement to hold allowances under this program. This approach relies on known data rather than future projections. The EPA believes this approach is preferable because any approach tied to future indicators (
The EPA proposes to allocate most CO
Although the EPA cannot anticipate the future EGU-level pattern of emissions, it is possible to consider potential future emission patterns at the source subcategory level. In developing the Clean Power Plan EGs, the agency conducted analysis of emission reduction potential in the two affected EGU source subcategories,
The EPA recognizes that states may prefer different approaches to distribute CO
The following sections discuss and request comment on the EPA's proposed approach to allocate CO
The EPA proposes to allocate most of the CO
(1) Clean Energy Incentive Program. This set-aside would be of first compliance period allowances only.
(2) Output-based allocation set-aside. This set-aside would start in the second compliance period and continue for each compliance period.
(3) Renewable energy set-aside. This set-aside would be implemented in all compliance periods.
This section describes the proposed historical-generation-based approach that the agency would use to allocate all allowances except for the set-aside allowances. The EPA is proposing affected-EGU-level allocations (based on available data) in every state. Further detail on this proposed allocation approach is provided in the Allowance Allocation Proposed Rule TSD in the docket. The affected-EGU-level allocations resulting from this proposed historical-generation-based approach are provided in the docket in an appendix to the TSD. The agency requests comment on the proposed historical-generation-based allocation approach and on other allocation approaches.
The EPA proposes to allocate the historical-generation-based portion of the allowances (
(1) For each unit in the list of likely affected EGUs in each state, identify annual net generation values for the historical period of 2010 through 2012 (reflecting affected-EGU-specific generation assumptions incorporated in the data adjustments,
The EPA proposes to use a 3-year historical period (
(2) Determine each affected EGU's average generation value by averaging all (non-zero) 2010 through 2012 annual generation values for the unit. The proposed approach would use only non-zero values in calculating a unit's average generation. For example, if generation data for a unit were available for only 2011 and 2012 then the EPA would only use the 2011 and 2012 values to determine the unit's unadjusted average generation value. The EPA included generation from all units in the historical data set in the proposed allowance calculations and calculated allowances for all such units; the agency requests comment on the treatment of generation from and allocations to units that operated in the historical data set but retire before the start of the program.
(3) In each state, sum the average generation values from all affected EGUs to obtain that state's “total average historical generation.”
(4) Divide each affected EGU's average generation value by the state's total average historical generation to determine that affected EGU's share of the state's total average historical generation.
(5) Multiply each affected EGU's share of the state's total average historical generation by the historical-generation-allocation portion of the state's mass goal (
The agency believes that this proposed historical-generation-based allocation approach is a reasonable approach for several reasons:
• The agency believes that the proposed historical-generation-based approach maximizes transparency and clarity of allowance allocations. The EPA has placed in the docket the historical generation data and the calculations used to determine the proposed affected-EGU-level allocations. The agency also placed the proposed affected-EGU-level allocations, resulting from these calculations, into the docket. These calculations can be relatively easily replicated.
• To calculate allocations, the EPA proposes to use historical affected-EGU-level net generation data compiled using a methodology similar to the Emissions & Generation Resource Integrated Database methodology. The proposed calculation approach is described further below and in the Allowance Allocation Proposed Rule TSD in the docket. The historical-data methodology is described in the CO
• Allocating based on historical data (as opposed to data not yet reported)
The proposed approach is transparent, based on reliable data, and, like the approaches used in the NO
The proposed historical-data-based allocations approach would not generally affect the ultimate pattern of generation across individual power plants, as compared to other methods of allocation. The combination of plants, and their contributing generation, that will be used to meet a particular demand for electric power will be based on the relative efficiency (cost of production) of available plants. The relevant measure of this efficiency is the marginal cost of generation, which for a particular power plant would be the sum of the cost of additional fuel to generate an additional MWh, additional maintenance costs to increase output by an additional MWh, and costs associated with the additional emissions that result from generating an additional MWh. In a mass-based trading program, additional emissions must be covered by additional allowances, so the cost of emitting is the price of the allowances that must be consumed to authorize those emissions. These emissions-related costs of electricity production are the same regardless of whether the allowances used to cover those emissions were initially allocated to the user or whether they were acquired subsequently in the marketplace.
The same concept applies to any other cost of electricity production. For example, a coal-fired EGUs operator would account for the cost of consuming coal to produce generation whether or not the coal was discovered already on-site, given to the unit at “no charge”, or purchased from the marketplace; in all cases, the combustion of that coal consumes its value (
The proposed historical-data-based allocation approach would not be expected to have any effect on freely competitive electricity markets, because the marginal cost of emitting under the mass-based trading program is determined by the level of the overarching mass goals and is not affected by the distribution of the underlying allowances. This marginal cost of emitting is what will inform prices, outputs, and competition among power plants. While cost-of-service markets are structured differently from competitive markets, the regulated utility still makes the dispatch decision on the basis of marginal costs among the units in its fleet, which is not affected by the amount of allowances that any particular unit in that fleet was initially allocated (assuming a competitive allowance market).
The EPA recognizes that some stakeholders are concerned about the potential future distribution of emissions at the facility level, and possible effects on communities. However, for the reasons discussed in the above paragraphs, allowance allocations that do not change based on future activity (such as allocations under the proposed historical-generation-based approach) do not affect the distribution of emissions under the program. This proposed rule is expected to achieve significant emission reductions across the electric power sector; see section IX of this preamble for discussion of anticipated broad benefits to communities.
In addition to the proposed historical-data-based allocations approach, the EPA also requests comment on other allocation approaches. One alternative approach on which the agency requests comment is similar to the proposed approach in that it allocates allowances based on historical generation. However, this alternative approach would divide the total number of allowances from a state's mass goal (minus the set-asides) into affected EGU source categories—based on analysis done in developing the source category-specific CO
In this alternative approach, for each state the EPA would multiply historical steam-generating-unit generation by the steam-generating-unit source category-specific CO
The EPA notes that there are multiple approaches that policymakers may use to distribute allowances, beyond the proposed or alternative allocation approaches we included in this proposed rule. Examples of other allocation approaches include allocating based on historical heat input (fuel) or historical emissions data, rather than historical generation data. The choice to use historical data for allocation (
The proposed and alternative allocation approaches would determine most of the allocations before the start of the program. Other potential allocation approaches would change allocations for future compliance periods based on future activity—referred to as “updating” allocations. This proposed rule includes an updating-allocation component, as we are proposing to set aside a portion of the allowances in each state for distribution using an updating output-based approach as detailed in section V.D.3 of this preamble. The EPA requests comment on the use of other updating allocation approaches.
Another allowance allocation approach that could minimize the difference between the initial allowance allocation and the ultimate distributional pattern of allowance use for compliance is to conduct an auction, a process whose express intent is to align the allocation of a scarce good (in this case, the limited authorization to emit CO
The EPA requests comment on an alternative approach, which is allocating a portion of the allowances to load-serving entities (LSEs) rather than to affected EGUs. LSEs are the entities responsible for delivering power to retail consumers.
Allocation to LSEs can help mitigate bill impacts on electricity consumers when applied in concert with certain additional design features. In particular, if LSEs commit and/or are required to pass through to ratepayers the value from their selling of the allocated allowances, this approach can mitigate the impact of electricity bill increases on consumers that might otherwise result from application of the federal plan. As described in the Allowance Allocation TSD, this type of approach can also help to avoid or mitigate the potential for windfall profits for affected EGUs. The EPA could apply this approach by conditioning the receipt of allowances by LSEs on the pass through to consumers of any allowance value if necessary.
The EPA requests comment on the design and utility of allocating allowances to LSEs to help mitigate electricity price impacts. In particular, the EPA requests comment on options to establish conditions requiring pass through of allowance value and verification of such pass-through, whether it would be appropriate to identify any conditions related to equitable distribution of allowance value among ratepayer categories, as well as the EPA's legal authority to apply any such conditions.
The EPA requests comment on the additional design aspects of any potential allocation to LSEs, including but not limited to the following questions: In particular, what metric should provide the basis for LSE allocation,
The EPA also requests comment on the proposed historical-generation-based allocation approach, the alternative approach that divides total allowances from a mass goal into source subcategories before allocating to individual affected EGUs within each source category based on historical generation, and on the other alternative approaches described in this section. The EPA also requests comment on allocating allowances to all generation in a state (including non-emitting generation) using a historical-generation-based approach. The agency also requests comment on the proposed allowance set-asides, which are detailed below. The agency requests comment on allocation approaches that may minimize the impact of this proposed rule on small entities. The EPA also requests comment on any other approaches to distribute allowances. The agency notes that we propose to provide that any state may choose to replace the federal plan allocation provisions with an allocation approach of its choosing as discussed below. Finally, with regard to alternative allocation methodologies (either those specifically mentioned in this proposal or other allocation methodologies), the EPA requests comment on how those alternatives would satisfy the requirement that in a mass-based program where new sources are not included as part of the program, the allocation methodology must address leakage to new fossil fuel-fired sources.
The proposed historical-data-based allocation approach—which the EPA proposes to use to allocate all of the allowances in each state except for the set-aside allowances—is a one-time determination that is not updated. The allocations resulting from this approach would be determined prior to the start of the program. The EPA proposes to record the historical-data-based allowances for each compliance period in source accounts prior to the start of each compliance period, and to record allowances for one compliance period at a time. Recording allowances prior to the start of a compliance period provides certainty to affected EGUs of their allocations in advance of when the allowances are needed for compliance and can facilitate long-term planning.
The agency proposes to record allowances for the mass-based trading program in accounts of affected EGUs 7 months prior to the start of each compliance period. For example, if compliance periods are 3 years long and the first compliance period comprises the years 2022, 2023, and 2024, the EPA would record allowances for 2022, 2023, and 2024 by June 1, 2021. The EPA requests comment on the proposed approach of recording allowances 7 months prior to the start of each compliance period, and on an alternative of recording allowances 13 months prior to the start of each compliance period. See section V.D.3 of this preamble for timing of recordation of allowances from the proposed set-asides.
In addition to the general allocation method proposed above, the EPA is proposing two additional components of allowance allocation under a mass-based federal plan. These two set-asides are being proposed to satisfy the requirement in the final guidelines that mass-based plans demonstrate that they have addressed the risk of leakage to new unaffected units, as specified below.
The final EGs specify the concern of leakage, which is defined in section VII.D of the final EGs preamble as the potential of an alternative form of implementation of the BSER (
As noted in the EGs, if a state were to adopt allowance set-aside provisions exactly as they are outlined in this model rule once it is finalized, the requirement for that state plan to address leakage would be considered presumptively approvable.
Section VIII.J of the final EGs provides a discussion of how set-asides can effectively address leakage in a mass-based plan approach. That section of the final EGs also describes why the allowance allocation alternative for addressing leakage must be chosen for the federal plan instead of the option to regulate new non-affected fossil fuel-fired EGUs. This is because the EPA does not have authority to extend regulation of and federal enforceability to new fossil fuel-fired sources under CAA section 111(d), and therefore we cannot include new sources under a federal mass-based plan approach.
The set-asides we are proposing—described in detail below—would establish a pool of allowances that would be allocated to affected EGUS or other entities based upon criteria designed to address leakage.
These set-asides are essentially a type of “economic incentive” authorized by the CAA as a means of pollution prevention and control, and the expected benefits of this particular type of economic incentive to address leakage make it appropriate here.
The EPA is aware of the successful use of set-asides and similar programs in other emissions trading programs. The following are examples of set-asides and similar programs used in other federal air quality rules.
The EPA has previously established set-asides of emissions allowances in FIPs under CAA section 110. For example, in the CSAPR, the EPA used a 5 percent set-aside for new units, because we believed it was “important to have a small new unit set-aside in each state to cover new units within the budget that was set aside in order to address the state's significant contribution and interference with maintenance.” (75 FR 45310; August 2, 2010). This was important, in the EPA's view, because it allowed for growth in the electric utility sector consistent with the EPA's modeling, where new units showed up in the modeling output as surrogate facilities representing potential new EGUs that come online in future years in response to demand increases or other market drivers.
As part of the ARP under Title IV of the 1990 CAA Amendments, Congress established a “conservation and renewable energy reserve” account.
In the NO
Below, the EPA describes two potential allowance set-asides. First, the EPA proposes a set-aside for allowances distributed to existing NGCC units based on output (
The EPA is proposing a set-aside approach referred to as output-based allocation, which provides targeted allocations of a limited portion of allowances to existing NGCC units as a means of mitigating leakage. The EPA believes that this proposed set-aside would reduce incentives for generation to shift away from EGUs covered under mass-based plans to new unaffected EGUs. We seek comment on all aspects of this proposal and its underlying rationale.
Under the output-based allocation approach we are proposing, beginning with the second compliance period, a portion of the total allowances within each mass-based federal plan state would be allocated to existing NGCC units based, in part, on their level of electricity generation in the previous compliance period. Each eligible EGU would get a larger allowance allocation from this set-aside if it generates more, such that owner/operators of eligible EGUs will have an incentive to generate more in order to receive more allowances. Because the total number of allowances is limited, this allocation approach will not exceed the overall emission goal. Instead, it merely modifies the distribution of allowances in a manner designed to align the generation incentives for eligible EGUs in mass-based states with new emitting EGUs that are not subject to a mass-based limit, mitigating emissions leakage.
The EPA is inviting comment on key parameters for the appropriate design of the output-based allocation approach used for this proposed set-aside. Key parameters to be identified under the output-based allocation approach include which affected EGUs receive the allocation, the timing of the set-aside's allocation procedure, the allocation rate(s), and the size of the set-aside. The EPA also invites comment on what other parameters may be relevant for design of an appropriate output-based set-aside.
The EPA first solicits comment on which EGUs should be eligible to receive output-based allocation from the set-aside. The EPA proposes that only NGCC units subject to the final EGs receive output-based allocation from the set-aside. The EPA recognizes that performance of output-based allocation may be improved by targeting which units receive this additional incentive. In particular, this approach can most effectively address emission leakage if targeted to those affected EGUs subject to a mass goal that face the greatest difference in their incentive to generate relative to otherwise similar EGUs that are not subject to a mass goal. As noted in the discussion of the allocation rate below, new combustion turbines (
The EPA also requests comment on extending output-based allocation from this set-aside to affected SGUs. Output-based allocation for SGUs may increase generation subject to the mass limit, leading to reduced generation and emissions from new emitting sources. However, the EPA does not propose this approach because it is not as effective as output-based allocation to NGCC units.
The EPA also proposes that this approach be targeted towards marginal generation that may not have otherwise occurred absent this set-aside, by providing allocations under this set-aside only to eligible EGUs that exceed a 50 percent capacity factor on a net basis over the compliance period, and only for the portion of their generation that exceeds that capacity factor.
The EPA also solicits comment on the timing of the output-based allocation set-aside's allocation procedure, which involves the relationship between the time at which eligible generation occurs and the vintage year(s) of the allowances allocated from this set-aside to recognize that generation. The EPA is proposing a lagged accounting procedure for this set-aside, where eligible generation that occurs during a given compliance period would receive allowances through this set-aside taken from vintage years in the subsequent compliance period. In keeping with this lagged accounting procedure, the EPA is proposing not to reserve any allowances of vintage years during the first compliance period (2022-2024) for allocation through this set-aside; eligible generation that occurs during the first compliance period would be recognized through this set-aside with allowances of vintage years from the second compliance period (2025-2027).
The EPA is proposing this lagged accounting procedure because the amount and location of eligible generation in any given compliance period remains uncertain until the compliance period has ended and the relevant data has been reported and verified. Without this lagged accounting procedure, the EPA would have to withhold an amount of allowances for this set-aside from certain vintage years even as the corresponding compliance period was already underway. Given the size of this proposed output-based allocation set-aside in certain states, the EPA believes it would be more advantageous for affected EGUs to know in advance how many allowances they will be allocated in a given period, inclusive of allowances allocated through this output-based allocation set-aside.
The EPA requests comment on options for the allocation rate under this approach. The allocation rate is the number of allowances, in an amount equal to a specific amount of emissions, that the affected EGU receives per one net MWh of generation eligible for the set-aside. The EPA proposes to set the allocation rate equal to the rate-based emission standard (on a net basis) for new NGCC units under 111(b), in order to align the generation incentives across EGUs eligible for the set-aside and the type of new emitting source that would generate more absent this set-aside. Specifically, an additional MWh of eligible generation would earn the affected EGU allowances equal to the level of emissions permitted per MWh of net generation under the 111(b) new source standard, which is 1,030 lbs/MWh-net (Carbon Pollution Standards for new, modified, and reconstructed EGUs). The EPA requests comments on other values for the allocation rate. For example the allocation rate may be the expected net emissions rate of newly constructed NGCC units, the historical average emissions rate from NGCC units, or the NGCC or fossil steam source category-specific emissions performance rates promulgated in the Clean Power Plan EGs (see section VI of the final EGs).
The EPA proposes to calculate an NGCC unit's capacity factor based on the previous compliance period's net generation and the net summer capacity of the unit. The EPA is proposing to require affected EGUs to report net generation to the agency.
The EPA proposes to determine the size of the output-based set-aside once, before the start of the program, and not to change the size thereafter. The EPA proposes to determine the size of the set-aside assuming that it would incentivize existing NGCC to increase utilization to a 60 percent capacity factor. The assumed 60 percent capacity factor offers a way to limit the size of this set-aside, which allows the remainder of the allowances in a given compliance period to be allocated through the historical-generation approach (as detailed above) and the other proposed set-asides (as detailed below). Furthermore, limiting the size of the set-aside avoids the risk of incentivizing too much generation from eligible sources, as discussed further in the Allowance Allocation Proposed Rule TSD.
The EPA proposes to determine the size of the output-based set-aside using 2012 baseline data from the Clean Power Plan EGs.
The set-asides resulting from this proposed approach are shown in Table 9 of this preamble. The set-asides in the table would apply to every compliance period except for the first compliance period for which there would be no output-based set-aside. Although the size of the set-aside would remain the same for each compliance period, as the mass goals decrease with each step in the Interim Period and to the Final Period, the set-asides would constitute an increasing share of a state's mass goal. The Allowance Allocation Proposed Rule TSD further details the proposed approach to determine the size of the set-aside. The EPA requests comment on a potential limit for the size of the set-aside in a compliance period based on a percentage of the state's total allowances for the compliance period.
Given the proposed limit on the total size of the set-aside, and the amount of potential generation eligible for the set-aside, there may be fewer allowances available in the set-aside than can be earned at the allocation rate. The EPA proposes that, if the amount of total generation eligible for the set-aside multiplied by the allocation rate exceeds the size of this set-aside, then the allowances in this set-aside would be allocated to eligible generation on a pro-rata basis.
The EPA proposes that if the number of allowances allocated from the set-aside is less than the size of this set-aside, then the remaining allowances would be distributed to all affected EGUs using the historical-generation-based approach described above.
The EPA proposes to provide notice of the capacity and generation data used to calculate allocations from the set-aside, and the resulting allocations, by August 1 of the first year in each compliance period,
The EPA requests comment on all aspects of the proposed approach to calculate output-based set-aside allocations. Further details are in the Allowance Allocation Proposed Rule TSD in the docket.
The EPA proposes to provide a set-aside of allowances for distribution to RE projects in each state covered by the proposed mass-based federal plan, and is also proposing this for the mass-based model rule. The agency also requests comment on whether distribution should extend to DS-EE, CHP, and other types of projects. Under this program, the EPA would reserve a percentage of each state's allowances in a set-aside account for each state. Developers of RE projects could apply to receive set-aside allowances based on the projected generation from eligible RE capacity.
This set-aside is expected to address concerns regarding leakage by lowering the marginal cost of production of the incented clean energy technologies within the state. This will make RE more competitive against new sources, reducing the potential for leakage to new sources. While the proposed set-asides would provide additional incentive for the creation of additional RE capacity, it should also be noted that the proposed mass-based trading program itself would provide incentive for new and existing low and zero-emitting generation.
In the context of the proposed federal plan, the EPA is proposing that it would create a unique set-aside for each state covered by a mass-based federal plan. Under a model rule, the state would create this set-aside. The allowances in each set-aside would be reserved from each vintage of the assigned mass goal to that state prior to allocation of allowances to sources. The EPA is proposing that 5 percent of allowances will be reserved from the allocation for each state for the purpose of the set-aside. We are also requesting comment on options for a percentage of allowances to be reserved ranging from 1 to 10 percent of total allowances in each state. The proposed percentage has been determined to provide a meaningful additional incentive for RE activities in each state, while ensuring that the vast majority of allowances are freely allocated to affected EGUs. The EPA made this conclusion based upon determining an appropriate volume of set-aside resources that, at a range of possible allowance prices, are projected to incent the development of additional RE projects. The analysis is provided in the docket as part of the Renewable Energy Set-aside TSD. We note that, under the proposed framework, these allowances would be available to affected EGUs either in the marketplace or through subsequent distribution of unclaimed set-aside allowances, and
In section V.D.5 of this preamble, below, the EPA is proposing that the size of the RE set-asides may grow over time as certain units shift out of the program.
We are proposing, as part of the mass-based federal plan and model rule, that a project is eligible to receive set-aside allowances if it is RE that meets the eligibility requirements for rate-based ERC issuance as specified in section IV.C of this preamble and section VIII.K of the final EGs. This includes, for example, the requirement that only capacity incremental to 2012 is eligible for the set-aside. The agency requests comment on an additional potential condition that would limit eligibility to project providers that are also the owners or operators of affected EGUs. This approach has precedent in the eligibility requirements for the ARP set-aside, and would limit the entities eligible to receive set-aside allowances to those that are subject to the federal plan.
The EPA is proposing that eligible RE capacity must meet the following conditions regarding geographic eligibility for both the federal plan and model rule. Eligible RE projects must be located in the mass-based state for which the set-aside has been designated. The agency invites comment on whether capacity outside the state should be recognized, and how that could be implemented. The EPA also proposes that the generation for which an entity receives allowances from the set-aside would not be eligible for ERC issuance in rate-based states.
As specified in section IV.C of this preamble, the EPA is proposing that the same RE measures are eligible to receive set-aside allowances under a mass-based federal plan as would be eligible for ERC issuance under a rate-based federal plan and the model rule. Specifically, the following RE measures are eligible: On-shore wind, solar, geothermal power, and hydropower. The RE measure must also have the capacity to provide data quantified by a revenue-quality meter, a requirement that is further discussed in section IV.D.8 of this preamble. New nuclear units and capacity uprates at existing nuclear units are not proposed to be eligible to receive set-aside allowances. We do not think a set-aside used as an incentive for incremental nuclear capacity is a useful way to address leakage to new sources during the performance period, due to unique costs and development timelines for incremental nuclear power. All other proposed aspects of the RE eligible measure types described in section IV.C of this preamble and the requests for comment included within that section also apply in the mass-based set-aside context for both the proposed mass-based federal plan and the proposed mass-based model rule. For example, we are requesting comment on the inclusion of other RE measures, incremental nuclear, demand-side EE measures, CHP and any other emission reduction measures beyond those mentioned here, as long as they meet the eligibility requirements outlined in the final EGs for rate-based crediting, as eligible measures to receive set-aside allowances. We particularly request comment on how a set-aside to provide an incentive from these particular measures will serve to address leakage to new sources. We also request comment on the implications of the inclusion of such technologies for the streamlined implementation of projection-based EM&V requirements of the set-aside specified below in a federal plan context across the applicable jurisdictions, while still maintaining necessary rigor. We request comment on the appropriateness of the biomass treatment requirements offered for comment in section IV.C.3 of this preamble in the context of a mass-based set-aside. We request comment on requirements for the treatment of CHP and WHP, in the context of the mass-based set-aside. We also request comment on appropriate processes through which, after the federal plan is finalized, the EPA and/or stakeholders could make a demonstration of the appropriateness of new measure types and the EPA could evaluate and approve the demonstration so that a new measure type can be considered eligible for the set-aside.
To demonstrate that an RE project meets the requirements proposed above, in the context of a mass-based federal plan, it is proposed that the project proponent must provide the following: Documentation of the nature of the project and that it meets eligibility requirements, documentation that it will be located within the state in question, and a projection of expected annual MWh generation for an RE project. The EPA must approve the documentation of eligibility and the projection of MWh before the project becomes eligible for a distribution of the set-aside allowances. In addition, the proponent must register for a general account in the EPA tracking system where the allowances would be recorded. See 40 CFR 62.16320 for the requirements to establish a general account. While the EPA is proposing to allow eligible resources to use a general account to receive any allowances allocated under this section, the EPA requests comment on extending the designated representative provisions in 40 CFR 62.16290 to eligible resources instead of the general account provisions. Requiring eligible resources to submit information similar to that collected in the certificate of representation in 40 CFR 62.16305 and to appoint a designated representative to act on behalf of all owners/operators for all projects requesting allowances may improve the EM&V process by making the eligible resources more accountable. The EPA requests comment on what documentation would be required if other measure types were considered eligible to receive set-aside allowances. We propose that the same process for approval of projects be applied in a model rule, with the state taking the approving role instead of EPA.
The EM&V requirements for the mass-based set-aside differ from those for rate-based ERC issuance, particularly because it is based upon projections provided prior to generation rather than metered data provided after the generation occurs (though we are proposing that the projections will be checked against ex-post metered data). The projection method enables the distribution of set-aside allowances prior to the year during which the generation occurs. The EPA feels this still provides sufficient rigor because the set-aside does not directly affect program stringency. The reason that stringency is not affected is because of key differences between issuance of credits and distribution of set-aside allowances. Under rate-based implementation, each decision to issue an ERC based on a quantification of RE generation affects the ultimate amount of allowable CO
The EPA proposes that the projections of MWh provided will be the basis of the distribution of set-aside allowances. A satisfactory demonstration of the future RE generation from an eligible project must use technically sound quantification methods that are reliable, replicable, and accompanied by underlying analytical assumptions and verifiable data sources used to demonstrate future performance. These methods, assumptions and data sources must be specified in documentation accompanying the projections. These projections and supporting documentation should all be provided in the set-aside project application, and that application must be approved by a third-party verifier. The EPA invites comment on these proposed requirements for projections. We also request comment on whether set-asides should be distributed proportional to actual MWh provided by the installation in a prior year or compliance period, or another form of historical generation data. This type of allocation method could also be similar to the structure proposed for the output-based allocation set-aside. We propose that the same projection-based distribution basis be applied in a model rule, with the state taking the approving role instead of EPA.
The EPA is proposing the following process for distribution of RE set-aside allowances. Starting prior to the compliance period, and going forward through the compliance period, RE providers in each state will have an opportunity to apply to the EPA or a designated agent to be approved as eligible to receive set-aside allowances in their state. This application must include all the requirements outlined above, including projections of expected MWh of generation. The EPA is proposing to accept RE set-aside project applications up to a deadline of June 1 in the year prior to the year during which the RE generation occurs (the “generation year”). The EPA or its agent will review and approve the project as eligible and it will be entered into the pool of projects that will receive set-asides in any compliance period. If approved, the number of projected MWh in each generation year will be the basis of the number of allowances the provider will receive, as an input to the methodology specified below. The providers will have an opportunity to update projections for future generation years, these projections must be received by June 1 of the year prior to the generation year in question.
On December 1 of the year prior to each year of the compliance period in question, the EPA is proposing to distribute allowances from the set-aside to approved providers. The agency is proposing to distribute set-aside allowances to approved RE providers pro-rata, with the number of allowances distributed to each provider according to the percentage of total approved RE MWh for that state that the approved MWhs from their project represent. This method is proposed because it treats all eligible RE projects equally in the distribution of set-aside allowance. It also inherently provides a more significant incentive in states with less eligible RE generation, but will become less significant as RE generation increases. We also request comment on whether to restrict projects to a maximum number of allowances they can receive per MWh of generation, such as 1 allowance per MWh.
After each generation year, RE providers receiving allowances will have to provide an M&V report with the MWhs of RE generation actually produced, to assure that they have met the projected level of generation. These M&V reports need to document that the generation was by an approved project, and the report should be approved by a third party verifier. As discussed in section IV.D.8 of this preamble (EM&V section for the rate-based approach), these data should be readily available from existing metering. The EPA requests comment on the process for submitting M&V reports with actual generation.
If the project or program does not reach the MWhs projected in a particular generation year, the unfulfilled MWhs will be subtracted from that RE provider's MWhs eligible for the set-aside in the next generation year, or multiple years if the deficit exceeds the MWhs projected for the upcoming year. If this deficit is greater than 10 percent in a particular year, the provider will need to provide an explanation of the deficit and will be required to reevaluate their projections for future years. If such deficits continue through all years of the relevant compliance period, the provider will be disqualified from receiving future set-asides for the following compliance period. We also request comment on whether a provider with continuing deficits should also be disqualified from receiving ERCs for the generation in question from states with rate-based plans. The agency requests comment on all of the specified aspects of this distribution process.
The EPA is proposing that once allowances have been distributed to all approved providers, any remaining allowances in the set-aside, such as set-aside allowances designated for projects that no longer exist, will be redistributed to affected EGUs in the state in a pro rata fashion on the same distribution basis as their initial allocations were made. It is proposed that this will occur immediately after the distribution of set-aside allowances to eligible RE providers on December 1 of the year prior to the generation year in question. The EPA requests comment on this approach.
We propose that the same distribution process as outlined above be applied in a model rule, with the state taking the approving role instead of the EPA.
The EPA is also seeking comment, in the context of the proposed rate-based federal plan and model rule, on whether a portion of this set-aside should be targeted to RE projects that benefit low-income communities. This benefit could be in the form of MWh provided to the low-income community, financial proceeds from the project primarily benefiting the low-income community, or the project lowering utility costs of low-income rate-payers. The EPA seeks comment on how a low-income community should be defined as eligible under this set-aside. We seek comment on how much of the set-aside should be designated as targeted at low-income communities. We also request comment on whether the methods of approval and distribution of allowances to projects that benefit low-income communities should differ from the methods that are proposed to apply to other RE projects.
The EPA seeks comment, in the context of the proposed rate-based federal plan and model rule, on all aspects of this proposed RE allowance set-aside program, including whether it should be included as part of a mass-
For purposes of the proposed mass-based federal plan, the EPA proposes to implement the Clean Energy Incentive Program (CEIP) on behalf of a state by issuing early action allowances for eligible actions located in or benefitting the state. Eligible projects must commence construction in the case of RE or commence operations in the case of low-income EE after September 6, 2018, and will receive incentives based on the zero-emitting MWh they generate, or the energy savings they achieve, during 2020 and/or 2021.
The EPA proposes to distribute the 300 million early action set-aside allowances among the states based upon the amount of the reductions from 2012 levels each state must achieve relative to that of the other participating states. The EPA proposes to calculate these values as each state's proportional share of the total difference between the 2012 baseline and the 2030 mass goals.
For the purposes of the mass-based federal plan, the EPA is proposing to award early action allowances to two types of eligible projects that are located in or benefit the state for which the EPA is implementing a federal plan:
• RE investments that generate metered MWh from any type of wind or solar resources; and
• Demand-side EE programs and measures implemented in low-income communities that result in quantified and verified electricity savings (MWh).
Eligible RE projects must commence construction, and eligible EE projects must commence implementation, after September 6, 2018 for those states on whose behalf the EPA is implementing the federal plan. These projects will receive incentives for the MWh they generate or the end-use energy demand reductions they achieve during 2020 and/or 2021.
The EPA proposes the following framework to implement the CEIP in the mass-based federal plan. First, the EPA proposes to create a set-aside of early action allowances for all federal plan states, as described above. Second, the agency proposes to create an account of “matching” allowances for each state participating in the CEIP—regardless of whether a state is implementing a state plan or the agency is implementing a federal plan on its behalf. This distribution would reflect each state's pro rata share of a federal pool of additional allowances—based on the amount of the reductions from 2012 levels the affected EGUs in the state are required to achieve relative to those in the other participating states
Following the effective date of a federal plan for a state, the agency will create an account of matching allowances for the state that reflects the pro rata share of the 300 million short ton CO
Third, for any state subject to a federal plan, the EPA proposes to award early action allowances and matching allowances to eligible projects as
• For RE projects that generate metered MWh from any type of wind or solar resources: For every two MWh generated, the project will receive a number of allowances equivalent to one MWh from the state early action allowance set-aside, and a number of matching allowances equivalent to one MWh from the EPA.
• For EE projects implemented in low-income communities: For every two MWh in end-use demand savings achieved, the project will receive a number of allowances equivalent to two MWh from the state early action allowance set-aside, and a number of matching allowances equivalent to two MWh from the EPA.
The EPA will address implementation details of the CEIP in a subsequent action. Allowances awarded by the EPA pursuant to the CEIP may be used for compliance by an affected EGU with its emission standards in any compliance period and are fully transferrable prior to such use. The EPA proposes to distribute any remaining early action set-aside allowances in a state—after distribution to all eligible projects in the state—to the affected EGUs in the state on a pro-rata basis in proportion to the initial allocations made to those EGUs under the mass-based federal plan.
As discussed in section V.E of this preamble, the EPA proposes to allow any state where a federal plan is being implemented to take responsibility for distributing allowances. This will allow a state to tailor its allowance-distribution approach to the characteristics and preferences of the state. The EPA proposes that a state that chooses to replace the federal plan allocations with a state-determined approach must include a CEIP set-aside, as authorized in section VIII.B.2 of the final EGs. The EPA intends that such a state would have the same flexibilities as a state implementing a full state plan with respect to implementation of the CEIP. That is, the state would not be required to implement a set-aside of the same size as proposed in Table 10 of this preamble, but rather could choose how many of its allowances to set-aside for the CEIP.
The EPA requests comment on all aspects of implementing the CEIP under a mass-based federal plan approach, including (1) The size of the early action allowance set-aside; (2) the approach for distributing the early action allowance set-aside among states; (3) the timing of distribution of set-aside and matching allowances; (4) the amount of allowances awarded per eligible MWh generated or avoided; (5) the criteria for eligible projects, including criteria for awards to EE projects implemented in low-income communities; (6) the mechanism for reviewing project submittals and issuing early action allowances; (7) EM&V requirements for eligible projects; and, (8) the number of early action and matching allowances that should be awarded for each ton of emissions reduced from eligible generation or low-income efficiency projects to ensure a robust response to the program. The EPA also seeks comment on how states, tribes and territories for whom goals have not yet been established in the final EGs may be able to participate in the CEIP in the future.
The EPA also requests comment on the proposed approach of requiring states to implement this program as a condition of a state choosing to determine its own allocation approach via a partial state plan or a delegation of the federal plan.
The EPA proposes to record allowances for each year of a multi-year compliance period at once, 7 months prior to the start of each compliance period, as discussed above. The agency proposes that, if an affected EGU does not operate for 2 full calendar years, then starting with the next compliance
The agency requests comment on this approach for treatment of allocations to affected EGUs that retire, including on the number of years of non-operation for which a unit would continue to receive allocations. The EPA also requests comment on an alternative of distributing such allowances to the set-aside for output-based allocations, or to the remaining affected EGUs in the state in a pro-rata fashion (on the same distribution basis as the initial allocations were made), instead of allocating such allowances to the state's RE set-aside. The agency requests comment on a further alternative approach, which would be to continue allocations to the retired units. The EPA also requests comment on treatment of allocations to units that are in long-term cold storage.
The EPA proposes to allow any state to replace the EPA-determined federal plan allowance-distribution provisions in the mass-based trading program with state-developed allowance-distribution provisions. In this way, a state could choose how to distribute initial allowance allocations among its affected EGUs (and other entities).
The EPA believes that this option may offer significant appeal, because it will allow a state to tailor its allocation approach to the characteristics and preferences of the state. A state would be able to design its allocation approach to address its particular state priorities, whether they are protecting low-income consumers, supporting local industries, or other goals. The EPA anticipates that a state would have great flexibility in its allowance distribution approach and could take advantage of allocation options discussed in this proposal as well as other allocation options a state might prefer. States could auction allowances and rebate the revenue to consumers, or allocate all allowances to load-serving entities, while mandating that the value be passed through to vulnerable consumers. The EPA believes that the state-determined allocation approach offers significant advantages and solicits comment on how to ease its application by states. This is similar to the approach taken in CSAPR and CAIR where the EPA adopted rules allowing states to submit SIPs with provisions replacing the allowance-distribution provisions in the CSAPR or CAIR FIPs, respectively, while remaining in the trading programs under those FIPs (76 FR 48208; August 8, 2011, 71 FR 25328; April 28, 2006). In both CSAPR and CAIR, some states have chosen to determine their own allocations under the FIPs. This form of SIP that can replace the allowance-distribution provisions in CSAPR or CAIR is termed an “abbreviated SIP revision.” In this proposed mass-based trading federal plan, the EPA proposes that a state may choose to submit a “state allowance-distribution methodology” (analogous to an abbreviated SIP revision) to replace the federal plan allowance-distribution provisions with allowance-distribution provisions of its choosing.
The mechanism the agency envisions is in the nature of a partial state plan or (for any future changes in a state's allocation methodology) a partial state plan revision. (We request comment below on the advantages and disadvantages of allowing a state to handle allocations via a delegation of federal plan authority.) In general, under the proposed approach, the procedural requirements states and the agency must follow, including public notice requirements, for the submission and approval of state plans, would be required here.
The EPA intends to provide the states with substantial flexibility in choosing approaches to distribute their allowances in a state allowance-distribution methodology. The EPA proposes that a state may choose any approach, including auctions or other methods the EPA is not proposing here, provided the state's approach addresses leakage and also implements the Clean Energy Incentive Program. The EPA is also requesting comment on any other appropriate constraints to impose on state allowance-distribution methodologies.
The Clean Power Plan EGs require mass-based state plans to include a demonstration that they have addressed the risk of leakage, and the EGs provide several options for doing so (
The Clean Power Plan EGs established a Clean Energy Incentive Program (section VIII of the final EGs). The EPA proposes that a state allowance-distribution methodology, which would replace the federal plan allocation provisions, must also include a Clean Energy Incentive Program, as detailed in section V.D.4 of this preamble.
Under the proposed approach of providing for states to determine their allowance distribution approaches in the federal plan mass-based trading program, the affected EGUs in a state that submitted a state allowance-distribution methodology, which the EPA approved, would participate in the federal plan mass-based trading program, but with allowance distribution determined by the state instead of by the EPA.
The EPA proposes that a state must submit to the Administrator tables specifying the unit-level allowances in an electronic format specified by the Administrator and by the specified deadlines applicable to each compliance period (
The EPA proposes that a state may submit a state allocation methodology for any compliance period, including the first compliance period, which would comprise the years 2022, 2023, and 2024. The EPA proposes that a state submitting a state allowance-distribution methodology to modify the federal plan allowance-distribution provisions must do so for all years within a compliance period (
The EPA proposes that, if the state's allowance-distribution provisions meet certain requirements and the state allowance-distribution methodology does not change any other provisions in the proposed mass-based trading program, then the agency would likely approve the state allowance-distribution methodology. In the state allowance-distribution methodology, the state could distribute allowances to affected EGUs or other entities (such as RE facilities) or could auction some or all of the allowances. The agency proposes that for EPA approval, the state allowance-distribution methodology provisions would have to meet the following requirements. The provisions would have to address leakage as discussed above. The provisions would have to provide that, for each year for which the state allowance-distribution provisions would apply, the total amount of allowances distributed could not exceed the applicable mass goal for that state for that year. A state's methodology under this proposed approach could provide that the total amount of allowances distributed is less than the applicable mass goal.
The allocation (or auction) of allowances would be final and could not be subject to modification. Additionally, the state's provisions could not change any other provisions of the proposed mass-based trading program with regard to the allowances (
In order for a state allowance-distribution methodology's provisions to replace the EPA's allowance-distribution provisions for a given compliance period, a state would have to submit the state allowance-distribution methodology by a deadline that would provide the agency sufficient time to review and approve it, and to submit the allowance table meeting the specified electronic format by a deadline that would provide sufficient time to record the unit-by-unit allowances in source accounts. The EPA believes that about 12 months—starting from the date of receipt of a state allowance-distribution methodology—is sufficient to complete the agency's review and approval process, which would have to provide an opportunity for public comment on the approval (or disapproval) action. Thus, the EPA proposes the following deadlines, in Table 11 of this preamble, for submission to the agency of state allowance-distribution methodologies and unit-level allowances, and for the EPA's recordation of allowances, for each compliance period. The EPA would review and approve state allowance-distribution methodologies in the 12 months between the proposed deadline for states to submit their methodologies and the proposed deadline for states to submit unit-level allowance tables. The proposed deadline for submission of allowance tables is 3 months before the proposed deadline for the agency to record allowances in source accounts. The EPA proposes to record allowances in source accounts by the recordation deadlines.
The proposed deadlines for submission of state allowance-distribution methodologies are later than the state plan submission deadlines promulgated in the Clean Power Plan EGs. The agency anticipates that it can complete the approval process relatively quickly for a state allowance-distribution methodology due to its narrow scope.
The agency proposes to record the EPA-determined federal plan allocations
In section V.D.2 of this preamble, the EPA proposes that the allowance recordation deadline be 7 months prior to the start of the compliance period (
The EPA proposes that a state may not replace EPA-determined allocations for a compliance period for which federal plan allocations have already been recorded, for the same reasons that the agency proposes that a state may not replace a mass-based trading federal plan with a state plan for a future compliance period for which allowances have already been recorded, as discussed below in section V.F of this preamble.
The agency requests comment on the proposed approach to allow states to determine allocations via state allowance-distribution methodologies and replace the federal plan allowance-distribution provisions. The EPA requests comment on the proposed schedule for submitting state allowance distribution methodologies to the agency, for submitting the resulting unit-level allowance tables to the agency, and for the agency to record allowances. The EPA requests comment on its proposed approach of not replacing EPA-determined allocations for a compliance period for which allowances have already been recorded. The agency also requests comment on an alternative approach where a state could notify the EPA of its intent to submit a state allowance-distribution methodology in advance, in which case the agency would hold off on recording EPA-determined allocations to allow more time for state-determined allowances to be recorded, similar to the alternative timing approach discussed in section V.F of this preamble.
The EPA is also requesting comment on an alternative approach to provide the opportunity for a state to determine its allowance-distribution provisions in the federal plan mass-based trading program. The alternative approach on which the agency requests comment is to provide for a partial delegation of the federal plan—limited to the allowance-distribution provisions—to a state that wishes to determine its allowance-distribution provisions. The EPA requests comment on the relative efficiency and ease of implementation of the two approaches (the state allowance-distribution methodology described above, or the partial delegation). The agency requests comment on whether the partial delegation approach would provide sufficient flexibility for a state to choose any method to distribute its allowances including approaches that the EPA is not proposing here. See further discussion of delegations in section VI of this preamble.
If the EPA implements a mass-based trading program federal plan for any state, the agency will work with a state that wishes to replace the federal plan with an approved state plan to provide a smooth transition. The EPA proposes that a mass-based trading federal plan could only be replaced by a state plan for a future compliance period for which allowances have not yet been recorded. For example, if a 3-year compliance period comprises 2022, 2023, and 2024, the EPA would record allowances in source accounts for 2022, 2023, and 2024 prior to 2022. Once 2022, 2023, and 2024 allowances had been recorded, the first compliance period for which a state could replace the federal plan with its own plan would be for the period commencing in 2025. The EPA is proposing this stipulation for the timing of replacing a federal plan with a state plan due to the need to avoid disruption to sources already subject to the mass-based trading federal plan. Without this stipulation, a state might withdraw from the mass-based trading program in the middle of a compliance period even though allowances that authorize emissions throughout that entire compliance period would already be in circulation. In that circumstance, the EPA would then need to address whether and how to remove those allowances from circulation to prevent inflation of the allowable emissions at affected EGUs in the remaining states subject to the federal plans beyond the levels specified in the Clean Power Plan EGs. The EPA believes it is more reasonable to avoid this potential disruption by requiring that the replacement of a federal plan with a state plan be scheduled to coincide with the conclusion of the last compliance period for which allowances under the federal plan have already been recorded for that state. The EPA requests comment on other approaches to provide a smooth transition from federal plan implementation to implementation by state plans, and on its proposed approach of not replacing a federal plan for any compliance period for which allowances were already recorded.
The agency requests comment on an alternative of providing for a state to give notice to the EPA of its intent to submit a state plan to replace the federal plan (or a state allowance-distribution methodology to replace federal plan allocations), and for the agency to delay recording federal plan allocations for sources in that state until a later date than proposed. The EPA requests comment on whether this alternative would help smooth the transition from federal plan implementation to state plan implementation, and on the trade-off between recording allowances in a timely way and providing this increased timing flexibility.
The EPA proposes that the mass-based trading program use an ATCS operated essentially the same way as the existing systems that are currently in use for CSAPR and the ARP under Title IV. Under the proposed mass-based trading program, the CO
The EPA proposes to establish procedures for certifying and authorizing the designated representative, and alternate designated representative, of the owners and operators of an affected EGU and for changing the designated representative and alternate designated representative. The proposed provisions describe the designated representative's and alternate designated representative's responsibilities and the process through which he or she could delegate to an agent the authority to make electronic submissions to the Administrator. These provisions are patterned after the provisions concerning designated representatives and alternates in prior EPA-administered trading programs.
Under the proposed provisions, the designated representative would be the individual authorized to represent the owners and operators of each affected EGU in matters pertaining to the mass-based trading program. One alternate designated representative could also be selected to act on behalf of, and legally bind, the designated representative and thus the owners and operators. Because the actions of the designated representative and alternate would legally bind the owners and operators, the designated representative and alternate would have to submit a certificate of representation certifying that each was selected by an agreement binding on all such owners and operators and was authorized to act on their behalf.
The designated representative and alternate would be authorized upon receipt by the Administrator of the certificate of representation. This document, in a format prescribed by the Administrator, would include: Specified identifying information for the affected EGU and for the designated representative and alternate; the name of every owner and operator of the affected EGU; and certification language and signatures of the designated representative and alternate. All submissions (
In order to change the designated representative or alternate, a new certificate of representation would have to be received by the Administrator. A new certificate of representation would also have to be submitted to reflect changes in the owners and operators of the affected EGU involved. However, new owners and operators would be bound by the existing certificate of representation even in the absence of such a submission.
In addition to the flexibility provided by allowing an alternate to act for the designated representative (
The proposed mass-based trading program rules include procedures and requirements for using and operating the ATCS (which is the electronic data system through which the Administrator would handle allowance allocation, holding, transfer, and deduction), and for determining compliance with the allowance-holding requirements in an efficient and transparent manner. Under the proposed rules, the ATCS would also provide the allowance markets with a record of ownership of allowances, dates of allowance transfers, buyer and seller information, and the serial numbers of allowances transferred. Consistent with the approach in prior EPA-administered trading programs, allowance price information would not be included in the ATCS. The EPA's experience is that private parties (
The proposed provisions addressing compliance and general accounts describe two types of ATCS accounts: Compliance accounts, one of which the Administrator would establish for each facility with an affected EGU upon receipt of the certificate of representation for the facility; and general accounts, which could be established by any entity upon receipt by the Administrator of an application for a general account. A compliance account would be the account in which any allowances used by an affected EGU for compliance with the emissions limitations would have to be held. The designated representative and alternate for the affected EGU would also be the authorized account representative and alternate for the compliance account. Using facility-level, rather than EGU-level accounts, would provide owners and operators more flexibility in managing their allowances for compliance, without jeopardizing the environmental goals of the mass-based trading program, because the facility-level approach would avoid situations where an EGU would hold insufficient allowances and would be in violation of allowance-holding requirements even though EGUs at the same facility had more than enough allowances to meet these requirements for the entire facility. Facility-level compliance would also be consistent with other EPA-administered mass-based trading programs.
General accounts could be used by any person or group for holding or trading allowances. However, allowances could not be used for compliance with emissions limitations so long as the allowances were held in, and not properly and timely transferred out of, a general account. To open a general account, a person or group would have to submit an application for a general account, which would be
The EPA proposes to establish the following schedule and procedures for recordation of allowance allocations and transfers. By June 1, 2021, the Administrator would record allowance allocations for EGUs for 2022 through 2024. Then, by June 1 of the year prior to the beginning of each compliance period, the Administrator would record the allowance allocations for the proposed mass-based trading program for each year within that next compliance period,
Under the proposed provisions, the process for transferring allowances from one account to another would be quite simple. Allowances could be transferred by submitting a transfer form providing, in a format prescribed by the Administrator, the account numbers of the accounts involved, the serial numbers of the allowances involved, and the name and signature of the transferring authorized account representative or alternate. If a transfer form containing all the required information were submitted to the Administrator and, when the Administrator attempted to record the transfer, the transferor account included the allowances identified in the form, the Administrator would record the transfer by moving the allowances from the transferor account to the transferee account within 5 business days of the receipt of the transfer form.
The EPA proposes to include the following provisions regarding compliance with emission limitations. Under the proposed provisions, once the compliance period has ended (
The EPA believes that it is important to include a requirement for an automatic deduction of allowances. The deduction of one allowance per allowance that the owners and operators failed to hold would offset this failure. The automatic deduction of another allowance per allowance that the owners and operators failed to hold that could not be avoided, regardless of any explanation provided by the owners and operators for their failure, would provide a strong incentive for compliance with the allowance-holding requirement by ensuring that non-compliance would be a significantly more expensive option than compliance. Such automatic deductions have been successfully used in prior programs including the CAIR, achieving compliance rates close to 100 percent.
The proposed provisions regarding allowance tracking and compliance also provide that the Administrator could, at his or her discretion and on his or her own motion, correct any type of error that he or she finds in an account in the ATCS. In addition, the Administrator could review any submission under the mass-based trading program, make adjustments to the information in the submission, and deduct or transfer allowances based on such adjusted information. These provisions are a standard part of other trading programs administered by the EPA including the ARP and Cross State Air Pollution Rule (
The EPA proposes that units subject to the mass-based federal plan trading program would monitor and report CO
The EPA is proposing to require affected EGUs in all states covered by the mass-based federal plan trading program to monitor and report CO
The majority of the units covered by this rule are already affected by the Acid Rain and/or RGGI programs and will have minimal additional monitoring and reporting requirements.
The EPA also requests comment on requiring monitoring and reporting of CO
Under section 111(d) of the CAA, the EPA adopts EGs that are then implemented when the EPA approves a state or tribal
If a state or tribe
If authority is not delegated to a state or tribe, the EPA will implement the federal plan. Also, if a state or tribe fails to properly implement a delegated portion of the federal plan, the EPA will assume direct implementation and
This proposed federal plan also specifies that EGU owners or operators who wish to petition the agency for any alternative requirement should submit a request to the Regional Administrator with a copy sent to the appropriate state.
There are two mechanisms for transferring implementation authority to state and local agencies and tribes: (1) EPA approval of a state or tribal plan after the federal plan is in effect; and (2) if a state or tribe does not submit or obtain approval of its own plan, EPA delegation to a state or tribe of the authority to implement certain portions of this federal plan to the extent appropriate and if allowed by state or tribal law. Both of these options are described in more detail below.
After EGUs in a state or area of Indian country become subject to the federal plan, the state or local agency or tribe may still adopt and submit a plan to the EPA. If the EPA determines that the state or tribal plan is satisfactory and approvable pursuant to the EGs, the EPA will approve the state or tribal plan. If the EPA, on review of the submitted state or tribal plan, determines that this is not the case, the EPA will disapprove the plan and the EGUs covered in the state or tribal plan would remain subject to the federal plan until a state or tribal plan covering those EGUs is approved and effective. Prior to disapproval, the EPA will work with states and eligible tribes to attempt to reconcile areas of the plan that are unapprovable.
Upon the effective date of an approved state or tribal plan, the federal plan would no longer apply to EGUs covered by such a plan and the state or local agency, or the tribe, would implement and enforce the state or tribal plan in lieu of the federal plan. The timing of effectiveness of an approved state or tribal plan in this circumstance may depend in part on the need to ensure a smooth transition and maintain regulatory certainty. Thus, for example, under a mass-based federal plan, we propose to handle these transitions so that they coincide with the compliance periods. The approval of a state or tribal plan would also involve a public comment process, which would give interested stakeholders including any affected EGUs, the opportunity to comment. This will assist in ensuring that compliance, program integrity, electric reliability, and other critical factors are maintained. When an EPA Regional Office approves a state or tribal plan, it will amend the appropriate subpart of 40 CFR part 62 or 40 CFR part 49, respectively, to indicate such approval, as well as the timing of its effectiveness.
As discussed elsewhere in this document, the EPA may also in certain circumstances approve a partial state or tribal plan (sometimes called an “abbreviated state plan”) that may modify certain limited provisions in the federal plan trading program. For example, this could occur if a state or tribe wishes to handle the initial allocation of allowances in a mass-based trading program, as discussed in section V.E of this preamble. The partial state or tribal plan would allow for the state or tribe to assume direct authority for administering and implementing this aspect of the trading program, while the remainder of the federal plan remains in place. The procedural and submission requirements set forth in the framework regulations of 40 CFR part 60, subpart B and the EGs would generally apply to a partial state or tribal plan, just as they would a full state or tribal plan. The scope of the requirement, however, would be commensurate with the scope of the partial plan. For instance, if a state or tribe seeks approval of a partial plan solely to handle allowance allocations, then the required statement of legal authority would be limited to those legal authorities the state or tribe must have to implement and enforce this component of the trading program.
The EPA, in its discretion, may delegate to state or tribal air agencies the authority to implement this federal plan. As discussed above, the EPA believes that it is advantageous and the best use of resources for state or local agencies or tribes to agree to undertake, on the EPA's behalf, administrative and substantive roles in implementing the federal plan to the extent appropriate and where authorized by state or tribal law. If a state or tribe requests delegation, the EPA will generally delegate the entire federal plan to the state or tribal agency, thereby providing authority to the state or tribe for things such as administration and oversight of compliance reporting and recordkeeping requirements, inspections of its affected EGUs, and enforcement. The EPA will continue to hold inspection, information gathering, enforcement, and other authorities along with the state or tribe even when a state or tribe has received delegation of the federal plan. The delegation will not include any authorities retained by the EPA.
The EPA Regional Administrators have been delegated the authority for implementing the federal plan. All reports required by the federal plan should be submitted to the appropriate Regional Administrator. Section II.B of this preamble includes Table 2 that lists names and addresses of the EPA Regional Office contacts and the states they cover.
With respect to the administration of a federal trading program in any final federal plan for a state or tribe, group of states or combined group of states and tribes, the Office of Air and Radiation within the Headquarters of the EPA is proposed to be the primary office within the agency with delegated CAA section 111(d)(2) authority.
Indian Tribes may, but are not required to, submit tribal plans to implement the EGs. Section 301(d) of the CAA and 40 CFR part 49 authorize the Administrator to treat an Indian Tribe in the same manner as a state (
The EPA is proposing in this action to find that it is necessary or appropriate to regulate affected EGUs in each of the three areas of Indian country that have affected EGUs under the proposed federal plan. The EPA is authorized to directly implement the EGs in Indian country when it finds, consistent with the authority of CAA section 301 which the EPA has exercised in 40 CFR 49.11, that it is necessary or appropriate to do so. In the final EGs, the EPA establishes emission performance rates for the four EGUs located in Indian country and
In this action, we are proposing to find that it is necessary or appropriate, in each of the three areas of Indian country that have affected EGUs, to establish a federal plan that applies to the four power plants located on the Navajo Nation, the Fort Mojave Indian Reservation, and the Uintah and Ouray Reservation of the Ute Tribe. The affected EGUs located on the Navajo Nation are in an area of Indian country located within the continental United States, are interconnected with the western electricity grid, and are owned and operated by entities that generate and provide electricity to customers in several states. The affected EGU located on the Uintah and Ouray Reservation of the Ute Tribe is in an area of Indian country located within the continental United States, is interconnected with the western electricity grid, and is owned and operated by an entity that generates and provides electricity to customers in several states. The affected EGU located on the Fort Mojave Indian Reservation is in an area of Indian country located within the continental United States, is interconnected with the western electricity grid, and is owned and operated by an entity that generates and provides electricity to customers in several states. To date, none of the three tribes on whose areas of Indian country the four power plants are located have expressed a clear intent to develop and seek approval of a tribal implementation plan. Thus, absent a federal plan, the significant emissions from these four power plants could go unregulated by the Clean Power Plan.
Because the agency has finalized emission performance targets for these power plants in the EGs, there is, in our view, little benefit to be had by not proposing to include them in a federal plan now and a potentially significant downside to not doing so; the reductions the EPA has determined are achievable in the EGs would become more difficult and costly for these power plants to achieve if they are delayed in entering into the trading program the agency intends to establish. In order to meet the performance targets, we are anticipating that the affected EGUs may need to secure allowances or ERCs (depending on the approach ultimately finalized) during the compliance periods. They may also be able to generate and sell compliance instruments by participating in the trading program. Thus, proposing a finding that it is necessary or appropriate to establish one or more federal plans providing the ability to participate in a rate- or mass-based trading program is in the interest of these four power plants located in areas of Indian country. We believe that this together with the facts that, as indicated above, all four EGU are interconnected with the western electricity grid and are owned and operated by an entity that generates and provides electricity to customers in several states thereby making it potentially disruptive and inequitable not to include them in one or more federal plans on the same schedule as other affected EGU strongly supports proposing to find that it is necessary or appropriate to establish one or more applicable federal plans at this time.
We recognize that the governments of these tribes may still choose to seek TAS to develop a tribal plan, and this proposed determination does not preclude the tribes from taking such actions. We also note that this proposed determination does not preclude these tribes from seeking TAS and receiving delegation to administer aspects of any applicable federal plan that is ultimately promulgated. In the event a federal plan is needed, proposing a necessary or appropriate finding at this time will allow the EPA to expeditiously promulgate a final federal plan for one or all of these power plants in the future to allow trading to occur. We will continue to consult with the governments of the Navajo Nation, Fort Mojave Indian Tribe, and the Ute Tribe of the Uintah and Ouray Reservation during the comment period for this proposal, and prior to taking any action to finalize a necessary or appropriate finding and/or a federal plan. Comments on the appropriateness of the proposed finding should be submitted within the comment period specified in the
As indicated in the final rulemaking action for the CAA section 111(d) guideline, “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” in this action, in addition to the proposed federal plans and model trading rules, the EPA is also proposing to amend the framework regulations and update the process for acting on CAA section 111(d) state plans under 40 CFR part 60, subpart B. These changes would be applicable to any future CAA section 111(d) rules going forward, not just the Clean Power Plan EGs. The EPA proposes six changes to the CAA section 111(d) process in the framework regulations to include: (1) Partial approval/disapproval mechanisms similar to CAA section 110(k)(3); (2) a conditional approval mechanism similar to CAA section 110(k)(4); (3) a mechanism for the EPA to make calls for plan revisions similar to the “SIP-call” provisions of CAA section 110(k)(5); (4) an error correction mechanism similar to CAA section 110(k)(6); (5) completeness criteria and a process for determining completeness of state plans and submittals similar to CAA section 110(k)(1) and (2); and (6) updates to the deadlines for the EPA action. In addition, in this section, the agency is proposing an interpretation regarding the effect under section 111 if an existing facility subject to CAA section 111(d) modifies or reconstructs. We believe these changes will significantly streamline the state plan review and approval process, be more respectful of state processes, and generally enhance the administration of the CAA section 111(d) program.
CAA section 111(d)(1) provides that the EPA “shall establish a procedure similar to that provided by CAA section [110] of this title under which each state shall submit to the Administrator a [111(d)] plan. . . .” 42 U.S.C. 7411(d)(1). Thus, the CAA directs the EPA to look to the structure of the SIP program when designing the procedures the states and agency will use to develop CAA section 111(d) plans. Notably, the CAA does not require the CAA section 111(d) procedures to be identical to those the EPA uses under
As a general matter these proposed changes would simply update the CAA section 111(d) framework regulations to include several new, more flexible procedural tools that Congress introduced into section 110 in the 1990 CAA Amendments. The basic procedures in the CAA section 111(d) framework regulations were promulgated in 1975 based on the structure of CAA section 110 as Congress designed it in the 1970 CAA.
First, the EPA proposes to add authority similar to that under CAA section 110(k)(3) to partially approve or disapprove a plan.
In cases where elements of a plan are functionally severable from each other, and one element is approvable while another is not, this provision will authorize the EPA to approve one part of a plan and disapprove the other. It will also authorize the EPA to accept and review a state plan that is only partial in nature, if identified by the state as such, so long as the other applicable submission requirements are met (such as demonstration of legal authority and completion of the public process). When the state submits what it intends to be a full state plan (rather than just a partial plan), the EPA proposes that the approvable portion of a plan must be functionally severable from the rest of the plan. This will be the case when the following conditions are met. First, the approvable portion of the plan must not depend on the rest of the plan. In other words, the disapproval of the remaining portion of the plan must not affect the portion that is approved. Second, approval of the approvable portion must not alter the function of the submittal in a way that is contrary to the state's intent.
The partial disapproval would be a disapproval for the purposes of CAA section 111(d)(2)(A) and would trigger the EPA's authority to issue a federal plan for the state, at least for that part of the plan that was disapproved. Incorporating this mechanism under the framework regulations for CAA section 111(d) will enable the EPA to approve a state to implement as much of its program as is consistent with a CAA section 111(d) guideline and may reduce the scope of any federal plan that would be necessary.
The second mechanism is the authority under CAA section 110(k)(4) to conditionally approve a plan. Where a state has submitted a plan that substantially meets the requirements of a CAA section 111(d) emission guideline, but requires some specific amendments to make it fully approvable, this provision authorizes the EPA to conditionally approve the plan. The Governor or his/her designee must submit to the EPA a commitment that specifies the amendments to be adopted and submitted to the EPA by no later than 1 year from the effective date of the conditional approval. If the state fails to meet its commitment, the conditional approval is treated as a disapproval. Incorporating this mechanism under the framework regulations for CAA section 111(d) will enable the EPA to approve a state to begin to administer a substantially complete program that requires only specific changes to be fully approvable. This provision is designed to authorize a state with a substantially complete and approvable program to begin implementing it, while promptly amending the program to ensure it fully complies with CAA section 111(d).
CAA section 110(k)(5) authorizes the EPA to find that a SIP does not comply with the requirements of the CAA. To date, the EPA has not considered using a similar procedure pursuant to the authority under CAA section 111(d). We now propose to do so. The ability to call for plan revisions is fundamental to a program that will be implemented over many years or multiple decades. Under the Clean Power Plan EGs, states have more than a decade to fully implement emissions standards or state measures in order to ensure affected EGUs achieve the emission goals of the EGs. Throughout this period, the EPA and the states will be monitoring their programs to ensure they are achieving the intended results. It is possible that design assumptions about the effect of control measures the states incorporate into their plans could prove inaccurate in retrospect and could result over time in the plan not meeting the emission reductions required by the EGs. In that case, having a procedural mechanism available under CAA section 111(d) similar to the so-called “SIP call” mechanism in CAA section 110(k)(5) will allow the agency to initiate a process with the state to make necessary
Accordingly, the EPA is proposing to amend the framework regulations to include a provision similar to CAA section 110(k)(5) under which the EPA may find that a state's CAA section 111(d) plan is substantially inadequate to comply with the requirements of the CAA and require the state to revise the plan as necessary to correct such inadequacies. Consistent with CAA section 110(k)(5), the EPA shall notify the state of any inadequacies and establish a reasonable deadline for the state to submit required plan revisions. That deadline will not exceed 18 months after the date of the action. The EPA will make its finding and notice to the state available to the public.
The effect of such a finding is that either the state submits the program corrections by the date the EPA sets in the document, or pursuant to CAA section 111(d)(2)(A), the EPA has authority to issue a federal plan for a state that misses its deadline to correct its plan. In effect, the finding of plan inadequacy establishes a plan submittal deadline subject to the provisions of CAA section 111(d)(2)(A). A finding of failure to meet that new deadline triggers the EPA's authority to issue a federal plan for the state. The EPA may promulgate a federal plan at any time following the state's failure to timely submit an adequate plan that addresses the EPA's finding.
While these authorities are important, the intention of having a mechanism to call for plan revisions is to have a way to initiate an orderly process to improve plans when they are not meeting program objectives. It is the EPA's hope that a call for plan revision leads to a constructive dialogue with a state or states, and ultimately, an improved and more effective CAA section 111(d) plan.
The EPA is also proposing that the agency can call for a plan revision in circumstances where a state is not implementing its approved state plan and, therefore, the state plan is substantially inadequate to provide for the implementation of CAA section 111(d) standards of performance. As discussed above, the CAA directs the EPA to develop a procedure for state plans under CAA section 111(d) similar to CAA section 110 SIP procedures. Calling a plan that is substantially inadequate to provide for implementation of standards of performance (
One critical requirement of CAA section 111(d)(1)(B) is that a state must submit a plan that “provides for the
In the alternative, the EPA proposes that this authority to call a plan for failure to implement is anchored in the authority provided under CAA section 110(k)(5) to call a SIP when the agency finds that it is “substantially inadequate to attain or maintain the relevant national ambient air quality standard.” In the context of CAA section 111, this authority translates into the EPA calling a state plan when the agency finds that it is substantially inadequate to achieve the emission reductions required under the EGs. If a state has failed to implement its plan, and that failure is pervasive enough to render the requirements of the plan ineffective, it is reasonable for the EPA to find that the state plan is substantially inadequate to achieve the emission reductions required under the EGs. The state's failure to implement has revised the effect of the plan so that it is no longer adequate to meet the CAA's requirements.
The fourth mechanism is the error correction authority under CAA section 110(k)(6). Where the EPA concludes that it has erroneously approved, disapproved, or promulgated a plan or plan revision (or part thereof), this section authorizes the agency to revise its action, in the same manner as the original action, without requiring any further submission from the state. Prior to the 1990 CAA Amendments, there was some question whether the EPA could unilaterally correct a previous action on a SIP submittal without the state having to submit a new SIP. This limitation imposed unnecessary burdens on states to fix even obvious errors, because CAA section 110(a)(2) requires the state to provide notice and a public hearing on each new SIP submittal. Incorporating this mechanism into the CAA section 111(d) framework regulations will allow the EPA to fix errors in its prior actions on state plans without imposing on the states the corresponding burden of providing notice and a public hearing as required under the CAA section 111(d) framework regulations.
Completeness criteria provide the agency with a means to determine whether a submission by a state includes the minimum elements that must be met before the EPA is required to act on such submission. When submittals do not contain the necessary minimum elements, then the EPA may, without further action, find that a state has failed to submit a plan. This determination is ministerial in nature and requires no exercise of discretion or judgment on the agency's part, nor does it reflect a judgment on the sufficiency or adequacy of the submitted portions of a state plan. The task is accomplished by simply comparing the materials provided by the state as its submittal against the required criteria to determine whether the plan is complete or not. In the case of SIPs under CAA section 110(k)(1), the EPA promulgated completeness criteria in 1990 at Appendix V to 40 CFR part 51 (55 FR 5830; February 16, 1990). The EPA proposes to adopt criteria similar to the criteria set out at section 2.0 of Appendix V for determining the completeness of submissions under CAA section 111(d). The completeness criteria can be grouped into: (1) Administrative materials; and (2) technical support. The EPA proposes that both groups would apply to all CAA section 111(d) rules going forward. The agency notes that the addition of completeness criteria in the framework regulations does not alter any of the submission requirements states already have under the EGs.
For administrative materials, the EPA is proposing completeness criteria that mirror the existing administrative criteria for SIP submittals because the two programs have similar
These criteria, as proposed, are intended to be generic to all CAA section 111(d) plans going forward, with the proviso that specific EGs may provide otherwise. The technical support completeness criteria that the EPA proposes will also be generic to all CAA section 111(d) rules, with the same proviso. The EPA proposes that the technical support required for all plans must include each of the following: (1) Description of the plan approach and geographic scope; (2) identification of each designated facility, identification of emission standards for each designated facility, and monitoring, recordkeeping, and reporting requirements that will determine compliance by each designated facility; (3) identification of compliance schedules and/or increments of progress; (4) demonstration that the state plan submittal is projected to achieve emissions performance under the applicable EGs; (5) documentation of state recordkeeping and reporting requirements to determine the performance of the plan as a whole; and (6) demonstration that each emission standard is quantifiable, non-duplicative, permanent, verifiable, and enforceable.
The EPA proposes a process similar, though not identical, to that set forth in 40 CFR 51.103 and Appendix V to 40 CFR part 51 to make completeness determinations. Similar to CAA section 110(k)(1)(C), under this proposal, where the EPA determines that a state submission required under CAA section 111(d) does not meet the minimum completeness criteria we are proposing to establish, the state will be considered to have not made the submission. The EPA further proposes that, similar to CAA section 110(k)(1)(B), within 60 days of the EPA's receipt of a state submission, but no later than 6 months after the date, if any, by which a state is required to submit the plan or revision, the Administrator shall determine whether the minimum criteria have been met. Any plan or plan revision that a state submits to the EPA, and that has not been determined by the EPA by the date 6 months after receipt of the submission to have failed to meet the minimum criteria, shall on that date be deemed by operation of law to meet such minimum criteria. In cases where a state does not submit anything to the agency, however, the Administrator must make a finding of failure to submit no later than 6 months after the date, if any, by which a state is required to submit the plan or revision. (In other words, “completeness by operation of law” is only available where the state has actually submitted a plan to the agency.)
As with the completeness determination process for SIP submissions, the EPA's determination that a submittal is complete is not a finding that the submittal meets the substantive requirements of CAA section 111(d) or the guideline. That must be done via the process for approval or disapproval of a state plan, which would be done through notice and comment rulemaking. In the completeness process, the EPA will confirm that a state's submittal appears to have addressed the criteria for a complete submittal and, therefore, the submittal is sufficient to trigger the EPA's obligation to act on it. But in the completeness process the agency will not assess the content of those submissions to determine if they are approvable. Accordingly, even when the EPA affirmatively determines that a submittal is complete, it does not prevent the agency from later finding that the state plan does not meet the requirements of the EGs, including finding that the submittal failed to address a required element and must be disapproved.
Similarly, when a submittal is determined to be complete by operation of law after 6 months without the EPA's affirmative determination of completeness, the only legal consequence is that the EPA now has an obligation to act on that submittal. Completeness by operation of law means that the submittal is deemed complete and requires the EPA's review, whether or not the state has actually addressed all the required elements. Accordingly, if the agency determines that a state has failed to address a required element in its submittal once the EPA begins review of the state plan that is complete by operation of law, the agency must go through the process of disapproving (or partially disapproving or conditionally approving, as discussed below) that plan, unless the state and the EPA work together to cure the deficiency. In other words, the EPA cannot simply find the plan incomplete and return it to the state at that point. But the finding of completeness by operation of law in no way prevents the EPA from subsequently concluding that the state's submission is missing a required element of the program and making that finding as part of a disapproval of the plan.
As described in the final rulemaking action for the CAA section 111(d) EGs, a state will submit all CAA section 111(d) plans electronically. If the EPA determines that any submission fails to meet the completeness criteria, the agency may return the plan to the state and request corrections, identifying the components that are absent or insufficient to allow the EPA to perform a review of the plan. The state will not have met its obligation to submit a final plan until it resubmits a revised state plan or supporting materials addressing the corrections the EPA identified in its incompleteness determination.
The EPA is also proposing to include an exception to the criteria for complete administrative materials in cases where a state and the EPA are “parallel processing” the final plan. Parallel processing allows a state to submit the plan prior to final adoption by the state and provides an opportunity for the
The EPA proposes to update the deadlines for acting on state submittals and promulgating a federal plan under 40 CFR 60.27(b), (c), and (d) to more closely track the current versions of CAA sections 110(c) and 110(k) adopted in 1990. The framework regulations for CAA section 111(d) state plans currently are parallel to the prior version of CAA section 110. They require the EPA to act on a state plan or plan revision submittal within 4 months after the date required for submission of a plan or plan revision.
The final CO
The EPA is proposing to amend 40 CFR 60.27(b) to allow the EPA 12 months to approve or disapprove submittals of all plans or plan revisions under CAA section 111(d), not just those related to the Clean Power Plan under 40 CFR 60.5715. This change would provide the EPA with sufficient time for the steps required to approve or disapprove the submittal, which include proposing the EPA's approval or disapproval of the plan or plan revision, a public comment period on the EPA's proposal, time for the EPA to review and respond to public comments, and the issuance of a final rule approving or disapproving the plan or plan revision.
The EPA is also proposing to amend 40 CFR 60.27(b) to specify that the deadline for the EPA to act on a plan or plan revision is 12 months after receipt of a complete plan or plan revision, rather than 12 months after the deadline for submittal of a plan or plan revision. This amendment will allow the EPA to have the full 12 months to act on submittals of complete plans or plan revisions.
The EPA also proposes slight modifications to the provision related to issuing a proposed federal plan in 40 CFR 60.27(c); changing the 6-month deadline for issuing a final federal plan in 40 CFR 60.27(d) to 1 year;
The EPA believes it is appropriate to modify these timing requirements for several reasons. First, the EPA notes that under CAA section 111(d)(2), Congress gave the EPA the “same” authority to prescribe a federal plan under CAA section 111(d) as it would have under CAA section 110(c) in the case of a state failure to submit a SIP. The term “same” stands in contrast to the term “similar” in CAA section 111(d)(1) (discussed above). As with the use of the term “similar,” the EPA believes it is authorized by this language to follow the timing provisions of CAA section 110(c) as currently enacted. Second, as a general matter, the timing requirements of current 40 CFR 60.27(c) and (d), which effectively require the EPA to propose and finalize a federal plan within 6 months of the deadline for state submittals, may be outdated and unrealistic with respect to the timelines for review of state plans and the time periods for action, particularly as informed by the agency's experience with CAA section 110 SIPs (which led to the extension of the timelines and other changes to CAA section 110 in the 1990 Amendments discussed above). Third, in the Clean Power Plan EGs, the EPA has finalized a timing requirement that gives the agency a year to approve or disapprove a state plan or revision. The existing requirement in 40 CFR 60.27(d) that the EPA must promulgate a federal plan within 6 months of the initial deadline for state plans is therefore inconsistent with this provision. Fourth, existing 40 CFR 60.27(c) tracks the prior version of CAA section 110(c) with respect to the issuance of a proposed federal plan. This relatively prescriptive language is no longer present in CAA section 110(c). The procedural requirements for rulemakings under both CAA section 110 and 111(d) are set out in section 307(d) of the CAA, and the EPA believes those provisions are appropriate and adequate to guide its rulemaking process for CAA section 111(d) federal plans.
The EPA invites comment on all of these proposed changes to the framework regulations. The EPA notes that the addition of these mechanisms to the framework regulations will make them available for all CAA section 111(d) regulations, not just those under the Clean Power Plan at 40 CFR part 60, subpart UUUU.
In the proposed rulemaking for the Clean Power Plan, the EPA proposed the interpretation that if an existing source is subject to a CAA section 111(d) state plan, and then undertakes a modification or reconstruction, the source remains subject to the state plan, while also becoming subject to the modification or reconstruction requirements.
We noted in the Clean Power Plan proposal that CAA section 111(d) is arguably silent as to this issue. Thus, we
We received many comments disagreeing with this approach. After reviewing these comments, the agency believes an alternative interpretation is more appropriate in the particular context here. In order to give the public an opportunity to comment on this, we are proposing this interpretation here. That is, when CAA section 111(d) EGs are initially promulgated for existing stationary sources in response to corresponding CAA section 111(b) standards of performance for the same pollutant, the statute prevents new, modified, or reconstructed sources (including under those particular CAA section 111(b) standards of performance and as those terms are applied in the relevant new source performance standards (NSPS)) from simultaneously being subject to state plans under those particular CAA section 111(d) EGs. This interpretation gives meaning to the definition of “existing source” in CAA section 111(a)(6) and is consistent with the definition of “new source” in CAA section 111(a)(2). Further, it is consistent with the historical treatment of modified and reconstructed sources in the CAA section 111 program.
The EPA notes the concerns it noted in the proposal supporting why the originally proposed interpretation was reasonable are being addressed in other ways in the final EGs, and in the proposed federal plan. In other words, there will be other ways to minimize disruption to state plans if such a modification or reconstruction were to take place. We invite comment on the agency's proposed interpretation that when an existing source modifies or reconstructs in such a way that it meets the definition of a new source, for purposes of a particular NSPS and emission guideline, it becomes a new source under the statute and is no longer subject to the CAA section 111(d) program
The agency intends to finalize these procedural changes and interpretation sooner than it finalizes the rest of this proposed action. The EPA believes these changes generally enhance and improve the framework regulations in a way that will be of benefit to the states, the EPA, and other stakeholders, and will improve the overall efficacy of the program. We believe it is important to finalize these changes to the framework regulations relatively quickly in order to provide states and other stakeholders predictability in how the EPA intends to process state plans and submissions under CAA section 111(d). If the EPA does finalize these changes sooner than the model trading rules or the federal plan, it will do so after the close of the comment period, and after consideration and response to any comments on these changes.
Consistent with the requirements of section 7(a)(2) of the Endangered Species Act (ESA), the EPA has considered the effects of this proposed rule and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to listed endangered or threatened species or designated critical habitat. Section 7(a)(2) of the ESA requires federal agencies, in consultation with the U.S. Fish and Wildlife Service (FWS) and/or the National Marine Fisheries Service, to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of federally listed endangered or threatened species or result in the destruction or adverse modification of designated critical habitat of such species.
The EPA has considered the effects of this proposed rule and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to listed species or designated critical habitat for purposes of ESA section 7(a)(2) consultation. The EPA notes that the projected environmental effects of this proposal are, like the EGs that it implements, positive: Reductions in overall GHG emissions, and reductions in PM and ozone-precursor emissions (sulfur oxides and NO
With respect to the projected GHG emission reductions, the EPA does not believe that such reductions trigger ESA consultation requirements under ESA section 7(a)(2). In reaching this conclusion, the EPA is mindful of significant legal and technical analysis undertaken by FWS and the U.S. Department of the Interior (DOI) in the context of listing the polar bear as a threatened species under the ESA. In that context, in 2008, FWS and DOI expressed the view that the best scientific data available were insufficient to draw a causal connection
The EPA has also previously considered issues relating to GHG emissions in connection with the requirements of ESA section 7(a)(2). In the final EGs, the agency noted that, although the GHG emission reductions projected for the EGs are large (estimated reductions of about 415 million short tons of CO
With regard to non-GHG air emissions, the EPA is also projecting substantial reductions of SO
Finally, the EPA has also considered other potential effects of the rule (beyond reductions in air pollutants) and whether any such effects are “caused by” the rule and “reasonably certain to occur” within the meaning of the ESA regulatory definition of the effects of an action.
The EPA has carefully considered the comments and the correspondence from Congress as well as the case law and other materials cited in those documents. The EPA does not believe that the effects of potential future changes in the energy sector—including increased reliance on wind or solar power as a result of future potential actions by states or other implementing entities—or any potential alterations in the operations of any particular facility would, at the time of promulgation of a federal plan, be sufficiently certain to occur so as to require ESA consultation on the rule. The EPA appreciates that the ESA regulations call for consultation where actions authorized, funded, or carried out by federal agencies may have indirect effects on listed species or designated critical habitat. However, as noted above, indirect effects must be caused by the action at issue and must be reasonably certain to occur.
Under a federal plan, it is the EPA that would implement a CAA section 111(d) plan. The EPA believes that even with this proposed federal plan, any effects on listed species or designated habitat are too uncertain to require consultation under ESA section 7. This is so for at least two reasons: (1) The EPA cannot know with any certainty at this stage which states will actually become subject to a finally promulgated federal plan. Which affected EGUs, in which states, will be covered by this plan can only be known after states have failed to submit a plan, or have had their plans disapproved by the EPA; and (2) the federal plan as proposed will be implemented through some form of emissions trading. Emissions trading inherently provides maximum flexibility to individual affected EGUs to choose their method of compliance, including continuing to emit the relevant pollutant at historical rates so long as the affected EGU holds sufficient credits or allowances. At this point, the EPA has no meaningful information to express in any more than the broadest terms how any particular affected EGU may choose to comply with the federal plan, should it be promulgated for them based on their location in an area not covered by an approved state plan. The Services have explained that ESA section 7(a)(2) was not intended to preclude federal actions based on potential future speculative effects.
The EPA anticipates significant emission reductions under this proposed action for the utility power sector. Specifically, the EPA is proposing approaches in the form of mass- and rate-based trading options that provide flexibility in implementing emission standards for a state's affected EGUs. Both proposed approaches to the federal plan would require affected EGUs to meet emission standards set using the CO
However, at the time of this proposal, the EPA has no information on whether any or how many states will require a federal plan or will adopt a model rule. Because of this lack of information, in the Regulatory Impact Analysis (RIA) for this proposal, the EPA chose to examine a scenario where all states of the contiguous United States will be regulated under a federal plan or will adopt the model rule. Additionally, we examine two alternative federal plan approach scenarios. The first federal plan approach assumes all states in the contiguous United States are regulated under a rate-based federal plan. The second federal plan approach assumes all contiguous states are regulated under a mass-based federal plan.
Under the rate-based approach, when compared to 2005, CO
The reductions in Tables 12 and 13 of this preamble do not account for reductions in HAP that may occur as a result of this rule. For instance, the fine particulate reductions presented above do not reflect all of the reductions in many heavy metal particulates.
The proposed action may have important energy market implications. Table 14 of this preamble presents a variety of important energy market impacts for 2020, 2025, and 2030 under both the rate-based and mass-based federal plan approaches described in section VIII.B of this preamble and presented in the RIA for this proposal.
These figures reflect the EPA's modeling that presumes policies that lead to generation shifts and growing use of DS-EE and renewable electricity generation out to 2029. If different implementation choices are made than those modeled, impacts could be different.
The compliance costs of this proposed action are represented in this analysis as the change in electric power generation costs between the base case and modeled federal plan approaches described in section VIII.B of this preamble and presented in the RIA for this proposal. The incremental cost is the projected additional cost of complying with the proposed action in the year analyzed and includes the amortized cost of capital investment, needed new capacity, shifts between or among various fuels, deployment of DS-EE programs, and other actions associated with compliance. These important dynamics are discussed in more detail in the RIA in the rulemaking docket.
The EPA estimates the annual incremental compliance cost for the rate-based federal plan approach to be $2.5 billion in 2020, $1.0 billion in 2025 and $8.4 billion in 2030. The EPA estimates the annual incremental compliance cost for the mass-based federal plan approach to be $1.4 billion in 2020, $3.0 billion in 2025, and $5.1 billion in 2030. More detailed cost estimates are available in the RIA in the rulemaking docket.
Based on the analysis presented in the RIA, the proposed action is projected to result in certain changes to power system operation as a compliance approach with the standards. See Table 14 of this preamble for a variety of important energy market impacts for 2020, 2025, and 2030 under both the rate-based and mass-based federal plan approaches described in Section VIII.B of this preamble and presented in the RIA for this proposal.
Changes in price or demand for electricity, natural gas, and coal can impact markets for goods and services produced by sectors that use these energy inputs in the production process or supply those sectors. Changes in the cost of production may result in changes in prices, quantities produced, and profitability of affected firms. The EPA recognizes that the EGs provide significant flexibilities and states implementing the EGs may choose to mitigate impacts to some markets outside the utility power sector. Similarly, demand for new generation or DS-EE as a result of states implementing the guidelines can result in shifts in production and profitability for firms that supply those goods and services.
Executive Order 13563 directs federal agencies to consider the effect of regulations on job creation and employment. According to the Executive Order, “our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth,
The EPA's employment analysis includes projected employment impacts associated with modeled federal plan approaches for the electric power industry, coal and natural gas production, and DS-EE activities. These projections are derived, in part, from a detailed model of the utility power sector used for this regulatory analysis, and U.S. government data on employment and labor productivity. In the electricity, coal, and natural gas sectors, the EPA estimates that the proposed action could result in a net decrease of approximately 25,000 job-years in 2025 under the rate-based federal plan approach and approximately 26,000 job-years in 2025 under the mass-based approach. For 2030, the estimates of the net decrease in job-years are 31,000 under the rate-based approach and 34,000 under the mass-based approach. The agency is also offering an illustrative calculation of potential employment effects due to DS-EE programs. Employment impacts from DS-EE programs in 2030 could range from approximately 52,000 to 83,000 jobs under the proposal.
By its nature, DS-EE reduces overall demand for electric power. The EPA recognizes as more efficiency is built into the U.S. power system over time, lower fuel requirements may lead to fewer jobs in the coal and natural gas extraction sectors, as well as in fossil fuel-fired EGU construction and operation than would otherwise have been expected. The EPA also recognizes the fact that, in many cases, employment gains and losses that might be attributable to this rule would be expected to affect different sets of people. Moreover, workers who lose jobs in these sectors may find employment elsewhere just as workers employed in new jobs in these sectors may have been previously employed elsewhere. Therefore, the employment estimates reported in these sectors may include workers previously employed elsewhere. This analysis also does not capture potential economy-wide impacts due to changes in prices (of fuel, electricity, or labor, for example) or other factors such as improved labor productivity and reduced health care expenditures resulting from cleaner air. For these reasons, the numbers reported here should not be interpreted as a net national employment impact.
Implementing the proposed action will generate benefits by reducing emissions of CO
The EPA has used the social cost of carbon (SC-CO
The SC-CO
OMB's Office of Information and Regulatory Affairs received comments in response to a request for public comment on the approach used to develop the estimates. After careful evaluation of the full range of comments submitted to OMB, the IWG continues to recommend the use of the SC-CO
Concurrent with OMB's publication of the response to comments on SC-CO
The EPA, as a member of the IWG on the SC-CO
The four SC-CO
There are limitations in the estimates of the benefits from this proposal, including the omission of climate and other CO
The health co-benefits estimates represent the total monetized human health benefits for populations exposed to reduced PM
PM benefit-per-ton values are generated using two concentration-response functions, Krewski et al. (2009)
It is important to note that the magnitude of the PM
For the ozone co-benefits, we present the results as a range reflecting benefit-per-ton estimates which use several different concentration-response functions for mortality, with the lower end of the range based on a benefit-per-ton estimate using the function from Bell et al. (2004)
In this analysis, in estimating the benefits-per-ton for PM
In general, we are more confident in the magnitude of the risks we estimate from simulated PM
For this analysis, policy-specific air quality data are not available,
Every benefit analysis examining the potential effects of a change in environmental protection requirements is limited, to some extent, by data gaps, model capabilities (such as geographic coverage), and uncertainties in the underlying scientific and economic studies used to configure the benefit and cost models. Despite these uncertainties, we believe the air quality co-benefit analysis for this rule provides a reasonable indication of the expected health benefits of the air pollution emission reductions for the illustrative analysis of this proposed action under a set of reasonable assumptions. This analysis does not include the type of detailed uncertainty assessment found in the 2012 PM
We note that the monetized co-benefits estimates shown here do not include several important benefit categories, including exposure to SO
For more information on the benefits analysis, please refer to the RIA for this rule, which is available in the rulemaking docket.
In this section we provide an overview of the actions that the agency is taking to help ensure that vulnerable communities are not disproportionately impacted by this rulemaking.
As described in the Executive Summary, climate change is an EJ issue. Low-income communities and communities of color already overburdened with pollution are likely to be disproportionately affected by, and less resilient to, the impacts of climate change. This rulemaking will provide broad benefit to communities across the nation, as its purpose is to reduce GHGs, the most significant driver of climate change. While addressing climate change will provide broad benefits, it is particularly beneficial to low-income populations and some communities of color (in particular, populations defined jointly by ethnic/racial characteristics and geographic location) where people are most vulnerable to the impacts of climate change (a more robust discussion of the impacts of climate change on vulnerable communities is provided in the Executive Order 12898 discussion in section X.J of this preamble). While climate change is a global phenomenon, the adverse effects of climate change can be very localized, as impacts such as storms, flooding, and droughts are experienced in individual communities.
Vulnerable communities also often receive more than their fair share of conventional air pollution, with the attendant adverse health impacts.
The changes in electricity generation that will result from this rule will further benefit communities by reducing existing air pollution that directly contributes to adverse localized health effects. These air quality improvements will be achieved through this rule because the EGUs that emit the most GHGs also have the highest emissions of conventional pollutants, such as SO
By reducing millions of tons of CO
There are other ways in which the actions that result from this rulemaking may affect overburdened communities in positive or potentially adverse ways and we also heard about these from commenters on the EGs.
While the agency expects overall emission decreases as a result of this rulemaking, we recognize that some EGUs may operate more frequently. To the extent that we project increases in utilization as a result of this rulemaking, we expect these increases to occur generally in lower-emitting NGCC units,
In addition to the many positive anticipated health benefits of this rulemaking, it also will increase the use of clean energy and will encourage EE. These changes in the electricity generation system, which are already occurring, but may be accelerated by this program, are expected to have other positive benefits for communities. The electricity sector is, and will continue to be, investing more in RE and EE. The construction of renewable generation and the implementation of EE programs such as residential weatherization will bring investment and employment opportunities to the communities where they take place. It is important to ensure that all communities share in these benefits. And while we estimate that the benefits of this program will greatly exceed its costs (as noted in the RIA for this rulemaking), it is also important to ensure that to the extent there are increases in electricity costs, that those do not fall disproportionately on those least able to afford them.
The EPA has engaged with community groups throughout this rulemaking and we received many comments on the issues outlined above from community groups, EJ organizations, faith-based organizations, public health organizations, and others. This input has informed this proposed rulemaking and prompted the EPA to consider other steps that the agency can take in the short and long term to consider EJ and impacts to communities in federal plan development and implementation.
It has also prompted us to work with our federal partners to make sure that communities have information on federal resources available to assist them. We describe these resources below, as well as resources that the EPA will be providing to assist communities in accessing EE/RE and financial assistance programs.
Finally, and importantly, we recognize that communities must be able to participate meaningfully in the development of this rulemaking. In this section, we discuss the steps that the EPA will take to assist communities in engaging with the agency throughout the comment period of this rulemaking.
The EPA is committed to ensuring that there is no disproportionate, adverse impact on overburdened communities as a result of this proposed rulemaking. To provide information fundamental to beginning that process, the EPA has conducted a proximity analysis for this proposed rulemaking that summarizes demographic data on the communities located near power plants.
The proximity analysis provides detailed demographic information on the communities located within a 3-mile radius of each affected power plant in the United States. Included in the analysis is the breakdown by percentage of community characteristics such as income and minority status. The analysis shows a higher percentage of communities of color and low-income communities living near power plants than national averages. It is important to note that the impacts of power plant emissions are not limited to a 3-mile radius and the impacts of both potential increases and decreases in power plant emissions can be felt many miles away. Still, being aware of the characteristics of communities closest to power plants is a starting point in understanding how changes in the plant's air emissions may affect the air quality experienced by some of those already experiencing environmental burdens.
Although overall there is a higher fraction of communities of color and low-income populations living near power plants than national averages, there are differences between rural and urban power plants. There are many rural power plants that are located near small communities with high percentages of low-income populations and lower percentages of communities of color. In urban areas, nearby communities tend to be both low-income communities and communities of color. In light of this difference between rural and urban communities proximate to power plants and in order to adequately capture both the low-income and minority aspects central to environmental justice (EJ) considerations, we use the terms “vulnerable” or “overburdened” when referring to these communities. Our intent is for these terms to be understood in an expansive sense, in order to capture the full scope of communities, including indigenous communities most often located in rural areas, that are central to our EJ and community considerations.
As stated in the Executive Order 12898 discussion located in section X.J of this preamble, the EPA believes that all communities will benefit from this proposed rulemaking because this action directly addresses the impacts of climate change by limiting GHG emissions through the establishment of CO
The EPA has heard from vulnerable communities throughout the outreach process for the Clean Power Plan that it is imperative for communities to have an understanding of how rulemakings that target climate change work. They expressed a desire to know how these programs may benefit their communities and what the potential adverse impacts of the rules may be on their communities. We intend to provide
We have received feedback from communities that public hearings, webinars, and in-person meetings are the most effective ways to engage with them and to provide them with the information they need to understand the rulemaking process. Therefore, for this rulemaking, in addition to conducting public hearings for all members of the American public, the agency will hold a national webinar for communities in the early stages of the comment period. The goal of this webinar will be to walk communities through the highlights of the preamble, so they have an understanding of how the rulemaking may potentially affect their communities and they will have the contextual information they need to actively engage with the agency throughout the comment period.
Additionally, because we received positive feedback on the effectiveness of the face-to-face meetings conducted on the regional level, each region will be offering an outreach meeting(s) for communities. The goal of these meetings is to build a level of understanding on this rulemaking to enable vulnerable communities to actively engage with the agency throughout the comment period. Furthermore, we will follow up on common issues raised during the outreach meetings with national conference calls, specifically targeted for vulnerable communities.
In section V.D of this preamble, we outline that we are seeking comment on whether a portion of this set-aside should be targeted to RE projects that benefit low-income communities. Furthermore, the EPA is seeking comment on how a low-income community should be defined as eligible under this set-aside. We also seek comment on how much of the set-aside should be designated as targeted at over-burdened communities. We also request comment on whether the methods of approval and distribution of allowances to projects that benefit low-income communities should differ, and if so, in what manner, from the methods that are proposed to apply to other RE projects.
As discussed below, there are also many federal programs that can help low-income populations access the benefits of RE and EE, and the economic benefits of a cleaner energy economy.
In the coming months, the EPA will continue to provide information and resources for low-income communities on existing federal, state, local, and other financial assistance programs to encourage EE/RE opportunities that are already available to communities. For example, the EPA will provide a catalog of current or recent state and local programs that have successfully helped communities adopt EE/RE measures. The goal of these resources is to help vulnerable communities gain the benefits of this rulemaking. The use of these RE/EE tools can also help low-income households reduce their electricity consumption and bills.
Additionally, as part of the resources that we will be providing low-income communities, the EPA will provide information on the Administration's Partnerships for Opportunity and Workforce and Economic Revitalization (POWER) Initative and other programs that specifically target economic development assistance to communities affected by changes in the coal industry and the utility power sector.
Federal agencies have a history of bringing EE and RE to low-income communities. Earlier this summer, the Administration announced a new initiative to scale up access to solar energy and cut energy bills for all Americans, in particular low- and moderate-income communities, and to create a more inclusive solar workforce. As part of this new initiative, the U.S. DOE, the U.S. Department of Housing and Urban Development, U.S. Department of Agriculture, and the EPA launched a National Community Solar Partnership to unlock access to solar energy for the nearly 50 percent of households and businesses that are renters or do not have adequate roof space to install solar systems, with a focus on low- and moderate-income communities. The Administration also set a goal to install 300 MW of RE in federally subsidized housing by 2020 and plants to provide technical assistance to make it easier to install solar energy on affordable housing, including clarifying how to use federal funding for EE and RE. To continue enhancing employment opportunities in the solar industry for all Americans, AmeriCorps is providing funding to deploy solar energy and create jobs in underserved communities, and DOE is working to expand solar energy education and opportunities for job training.
These recent announcements build on the many existing federal programs and resources available to improve EE and accelerate the deployment of RE in vulnerable communities. Some examples of these resources include: The DOE's Weatherization Assistance Program, Health and Human Service's Low-Income Home Energy Assistance Program, the Department of Agriculture's Energy Efficiency and Conservation Loan Program, High Cost Energy Grant Program, and the Rural Housing Service's Multi-Family Housing Program.
The U.S. Department of Housing and Urban Development supports EE improvements and the deployment of RE on affordable housing through its Energy Efficient Mortgage Program, Multifamily Property Assessed Clean Energy Pilot with the State of California, PowerSaver Program, and the use of Section 108 Community Development Block Grants. The Department of Treasury provides several tax credits to support RE development and EE in low-income communities, including the New Markets Tax Credit Program and the Low-Income Housing Tax Credit. The EPA's RE-Powering America's Land Initiative promotes the reuse of potentially contaminated lands, landfills and mine sites—many of which are in low-income communities—for RE through a combination of tailored redevelopment tools for communities and developers, as well as site-specific technical support. The EPA's Green Power Partnership is increasing community use of renewable electricity across the country and in low-income communities. The EPA partners with EE programs throughout the country that leverage ENERGY STAR to deliver broad consumer energy-saving benefits, of particular value to low-income households who can least afford high energy bills. ENERGY STAR also works with houses of worship to reduce energy costs—savings that can then be repurposed to their community mission, including programs and assistance to residents in low-income communities. The EPA will be working with these federal partners and others to ensure that states and vulnerable communities have access to information on these programs and their resources.
The federal government also has a number of programs to expand employment opportunities in the energy sector, including for underserved populations. Examples of these include the U.S. Department of Housing and Urban Development, DOE, and the Department of Education's “STEM, Energy, and Economic Development” program; DOE's Diversity in Science and Technology Advances National Clean Energy in Solar (DISTANCE-
It is important to the EPA that the implementation of federal plans be assessed in order to identify whether they cause any adverse impacts on communities already overburdened by disproportionate environmental harms and risks. The EPA will conduct its own assessment during the implementation phase of this rulemaking to determine whether the implementation of federal plans and other air quality rules are, in fact, reducing emissions and improving air quality in all areas and, or whether there are localized air quality impacts that need to be addressed under the Clean other CAA authorities.
The EPA will provide trainings for communities on resources that they can use to assess localized impacts, especially effects of co-pollutants, of plans on their communities. This training will include guidance in accessing the publicly available information that sources and states currently report that can help with ongoing assessments of federal plan impacts. For example, unit-specific emissions data and air quality monitoring data are readily available. This information, together with the assessment that the EPA will conduct in the implementation phase of this rulemaking will enable the agency and communities to monitor any disproportionate emissions that may result in adverse impacts and address them.
Air quality in a given area is affected by emissions from nearby sources and may be influenced by emissions that travel hundreds of miles and mix with emissions from other sources.
Another effect of the final CO
The EPA is committed to helping ensure that this action will not have disproportionate adverse human health or environmental effects on vulnerable communities. Throughout the implementation phase of this rulemaking, the agency will continue to provide trainings and resources to assist communities and as they engage with the agency. The EPA, through its outreach efforts during the comment period, will continue to solicit feedback from communities on what they would like additional trainings and resources on.
As described above, the EPA will assess the impacts of this rulemaking during its implementation. The EPA will house this assessment, along with the proximity analysis and other information generated throughout the implementation process, on its Clean Power Plan Communities Portal that will be linked to this rulemaking's Web site (
The EPA consulted its May 2015,
In summary, the EPA in this proposed rulemaking has designed an integrative approach that helps to ensure that vulnerable communities are not disproportionately impacted by this rule. The proximity analysis that the agency has conducted is a central component of this approach. Not only is the proximity analysis a useful tool to help identify communities that may be impacted by this rulemaking; it will also help communities as they engage with the EPA throughout the comment period. It will help the EPA as we help low-income communities access EE/RE and financial assistance programs. Finally, in order to continue to ensure that overburdened communities are not disproportionately impacted by this rule, the EPA will be conducting an assessment during the implementation phase of the effects of this and other rules on air quality.
Additional information about these statutes and Executive Orders can be found at
This proposed action is an economically significant regulatory action that was submitted to the OMB for review. Any changes made in response to OMB recommendations have been documented in the docket for this rulemaking. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, which is contained in the “Regulatory Impact Analysis for the Proposed Federal Plan Requirements for Greenhouse Gas Emissions from Electric Utility Generating Units Constructed on or Before January 8, 2014; Model Trading Rules; Amendments to Framework Regulations” (EPA-452/R-15-006, July 2015), is available in the docket and is briefly summarized in section VIII of this preamble.
Consistent with Executive Order 12866 and Executive Order 13563, the EPA estimated the costs and benefits for two alternative federal plan approaches to implementing the proposed federal plan and model trading rules. The proposed action will achieve the same levels of emissions performance as required of state plans under the CAA section 111(d) EGs for the control of CO
The RIA for this proposal analyzed two implementation scenarios, which we term the “rate-based federal plan approach” and the “mass-based federal plan approach.” It is very important to note that the differences between the analytical results for the rate-based and mass-based federal plan approaches presented in the RIA may not be indicative of likely differences between the approaches. In other words, if one approach performs differently than the other on a given metric during a given time period, this does not imply this will apply in all instances.
It is important to note that the potential regulatory impacts presented in the Clean Power Plan Final Rule RIA and the RIA for this proposed rule are not additive. Both RIAs present estimates of the benefits and costs of achieving the emission performance rates of the Clean Power Plan EGs. In the case of the Clean Power Plan Final Rule RIA, the illustrative analysis assumes the performance rates are met under state plans. In the case of this RIA for the proposed federal plan and model trading rules, the same performance rates are accomplished but are assumed to be achieved under the federal plan or model trading rules.
The EPA has used the social cost of carbon estimates presented in the
The EPA estimates that, in 2020, this proposal will yield monetized climate benefits (in 2011$) of approximately $2.8 billion for the rate-based approach and $3.3 billion for the mass-based approach (3 percent model average). For the rate-based approach, the air pollution health co-benefits in 2020 are estimated to be $0.7 billion to $1.8 billion (2011$) for a 3 percent discount rate and $0.64 billion to $1.7 billion (2011$) for a 7 percent discount rate. For the mass-based approach, the air pollution health co-benefits in 2020 are estimated to be $2.0 billion to $4.8 billion (2011$) for a 3 percent discount rate and $1.8 billion to $4.4 billion (2011$) for a 7 percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE program and participant costs and monitoring, reporting, and recordkeeping costs in 2020, are approximately $2.5 billion for the rate-based approach and $1.4 billion for the mass-based approach (2011$). The quantified net benefits (the difference between monetized benefits and compliance costs) in 2020 are estimated to range from $1.0 billion to $2.1 billion (2011$) for the rate-based approach and from $3.9 billion to $6.7 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average).
The EPA estimates that, in 2025, the proposal will yield monetized climate benefits (in 2011$) of approximately $10 billion for the rate-based approach and $12 billion for the mass-based approach (3 percent model average). For the rate-based approach, the air pollution health co-benefits in 2025 are estimated to be $7.4 billion to $18 billion (2011$) for a 3 percent discount rate and $6.7 billion to $16 billion (2011$) for a 7 percent discount rate. For the mass-based approach, the air pollution health co-benefits in 2025 are estimated to be $7.1 billion to $17 billion (2011$) for a 3 percent discount rate and $6.5 billion to $16 billion (2011$) for a 7 percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE program and participant costs and MRR costs in 2025, are approximately $1.0 billion for the rate-based approach and $3.0 billion for the mass-based approach (2011$). The quantified net benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated to range from $17 billion to $27 billion (2011$) for the rate-based approach and $16 billion to $26 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average).
The EPA estimates that, in 2030, the proposal will yield monetized climate benefits (in 2011$) of approximately $20 billion for the rate-based approach and $20 billion for the mass-based approach (3 percent model average). For the rate-based approach, the air pollution health co-benefits in 2030 are estimated to be $14 billion to $34 billion (2011$) for a 3 percent discount rate and $13 billion to $31 billion (2011$) for a 7 percent discount rate. For the mass-based approach, the air pollution health co-benefits in 2030 are estimated to be $12 billion to $28 billion (2011$) for a 3 percent discount rate and $11 billion to $26 billion (2011$) for a 7 percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE program and participant costs and monitoring, reporting, and recordkeeping costs in 2030, are approximately $8.4 billion for the rate-based approach and $5.1 billion for the mass-based approach (2011$). The quantified net benefits (the difference between monetized benefits and compliance costs) in 2030 are estimated to range from $26 billion to $45 billion (2011$) for the rate-based approach and from $26 billion to $43 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average).
Table 18 and Table 19 of this preamble provide the estimates of the climate benefits, health co-benefits, compliance costs and net benefits of the proposal for rate-based and mass-based federal plan approaches, respectively.
There are additional important benefits that the EPA could not monetize. Due to current data and modeling limitations, our estimates of the benefits from reducing CO
The information collection requirements in this rule have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document prepared by the EPA has been assigned EPA ICR number
This rule does not directly impose specific requirements on state and U.S. territory governments with affected EGUs. The rule also does not impose specific requirements on tribal governments that have affected EGUs located in their area of Indian country. This rule does impose specific requirements on affected EGUs located in states, U.S. territories, or areas of Indian country.
The information collection activities in this proposed rule are consistent with those activities defined under the Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (
Aside from reading and understanding the rule, this proposed action would impose minimal new
Although the EPA cannot determine at this time how many affected EGU respondents will submit information under the federal plan, the EPA has estimated an “upper bound” burden estimate for this ICR that estimates burden should every affected EGU read and understand the rule. This is the only potential respondent activity that would be required under the 3-year period following publication of the final federal plan, as there are no obligations to respond in this period. The results of this upper bound estimate of federal plan burden are presented below:
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.
Submit your comments on the agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. You may also send your ICR-related comments to OMB's Office of Information and Regulatory Affairs via email to
Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along with regulatory alternatives that could minimize that impact. The complete IRFA is available for review within the RIA in docket EPA-HQ-OAR-2015-0199 and is summarized here.
The small entities subject to the requirements of this proposed rule may include privately-owned and publicly-owned entities, and rural electric cooperatives that are majority owners of affected EGUs. The EPA conducted this regulatory flexibility analysis at the highest level of ownership, evaluating parent entities with the largest share of ownership in at least one potentially-affected EGU included in EPA's Base Case using the IPM v.5.15, used in the RIA for this proposed rule. This analysis drew on parsed unit-level estimates using IPM results for 2030.
The EPA identified 223 potentially affected EGUs owned by 74 small entities included in 2030 projections from EPA's IPM v.5.15. Fifty-nine of these potentially affected EGUs are projected to no longer be operating by 2030 in the Base Case of EPA's version of IPM. Twenty-four small entities are projected to have all of their potentially affected EGUs cease operation by 2030 in this base case.
The EPA estimated net compliance costs for individual EGUs for the proposed rule using components for operating and annualized capital costs, fuel costs, demand-side energy efficiency program costs, and revenue changes. This approach is consistent with previous proposed power sector regulations, but also adds the additional component of change in demand-side energy efficiency program costs. Investment in demand-side energy efficiency results in lower electricity demand, and consequently fewer emissions as production is reduced to meet the lower demand, an important emission-reduction strategy modeled in the rate-based and mass-based federal plan approaches. For this analysis, the EPA used the parsed unit-level estimates to estimate three of the four components of the net compliance cost equation using IPM outputs: The change in operating and annualized capital costs, the change in fuel costs, and the change in revenue, where all changes are estimated as the difference between the base case and federal plan scenario. These impacts were then summed for each small entity, adjusting for ownership share. An additional analysis was performed outside of EPA's IPM model to estimate the change in demand-side energy efficiency program costs, based largely on IPM-projected outputs.
As noted earlier, there are 74 small entities with potentially affected EGUs that are modeled in the IPM base case in 2030. Of these, 24 small entities are projected to withdraw all of their potentially affected EGUs from operation under base case conditions. This leaves 50 small entities with potentially affected EGUs that are projected to be generating electricity in 2030. Under the rate-based federal plan approach, 7 of these 50 small entities are projected to withdraw all of their potentially affected EGUs from operation by 2030. Under the mass-based federal plan approach, 5 of these 50 small entities are projected withdraw all of their potentially affected EGUs from operation by 2030.
Under the rate-based federal plan approach, 23 small entities are projected to incur net compliance costs greater than 3 percent of generation revenues from their potentially affected EGUs. In contrast, 9 entities are estimated to have net compliance cost savings greater than 3 percent of their generation revenues from affected EGUs. Under the mass-based federal plan approach, 21 small entities are projected to incur net compliance costs greater than 3 percent of generation revenues from their potentially affected EGUs. In contrast, 11 entities are estimated to have net compliance cost savings greater than 3 percent of generation revenues from their affected EGUs.
There are uncertainties and limitations in this analysis that may result in estimates that diverge from what we might see in reality. For example, at the time of this proposal,
As discussed earlier in this preamble, the reporting, recordkeeping and other compliance requirements are most likely covered under 40 CFR part 75 and part 98 programs for affected EGUs. Therefore, only a marginal additional cost is expected for the monitoring, reporting and recordkeeping requirements of the proposed federal plan for affected EGUs.
Owners of affected EGUs may be subject to other related rules. For example, on September 20, 2013, the EPA proposed carbon pollution standards for new fossil fuel fired EGUs. On June 2, 2014, the EPA proposed carbon pollution standards for modified and reconstructed fossil fuel-fired EGUs, in addition to the Clean Power Plan EGs, to cut carbon pollution from existing fossil fuel-fired EGUs. These existing EGUs are, or will be, potentially impacted by several other recently finalized EPA rules. On February 16, 2012, the EPA issued the mercury and air toxics standards (MATS) rule (77 FR 9304) to reduce emissions of toxic air pollutants from new and existing coal- and oil-fired EGUs. On May 19, 2014, the EPA issued a final rule under section 316(b) of the Clean Water Act (33 U.S.C. 1326(b)). This rule establishes new standards to reduce injury and death of fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. On June 18, 2014 (79 FR 34830), the EPA promulgated the stream electric effluent limitation guidelines (SE ELG) rule to strengthen the controls on discharges from certain steam electric power plants. On April 17, 2015 (80 FR 21302), the EPA promulgated the coal combustion residuals (CCR) rule, which establishes technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating solid waste.
As required by section 609(b) of the RFA, the EPA also convened a Small Business Advocacy Review (SBAR) Panel to obtain advice and recommendations from small entity representatives that potentially would be subject to the rule's requirements. The SBAR Panel evaluated the assembled materials and small-entity comments on issues related to elements of an IRFA. A copy of the full SBAR Panel Report is available in the rulemaking docket.
The EPA also considered whether the separate changes that we are proposing to make, as explained in section VII of this preamble, to the framework regulations in subpart B of part 60 of the CAA regulations would have any impacts on small entities. Since these changes only modify and enhance the procedures that the Administrator will follow in processing state plans and promulgating a federal plan, and do not alter the rules or requirements that states or regulated entities must follow, the agency does not believe that there will be economic impacts on small entities from this portion of this proposal. After considering the economic impacts of the proposed changes to 40 CFR 60.27, I certify those changes will not have a significant economic impact on a substantial number of small entities.
This action contains a federal mandate under UMRA, 2 U.S.C. 1531-1538, that could potentially result in expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, or the private sector in any 1 year. This federal plan will apply only to those affected EGUs located in states that do not submit approvable state plans, which is a subset of the EGUs considered in the RIA for the final EGs (see RIA for this proposal for further discussion of impacts). Because it is impossible to determine at this time which states might be ultimately subject to a federal plan, the EPA cannot determine whether this rule, when finalized, will be subject to UMRA. However, as noted below, the agency has done substantial outreach to government entities as part of both the federal plan and the related CAA section 111(d) rulemaking. Further, regardless of whether the EPA does determine that this action ultimately meets the UMRA threshold, the agency intends to do additional outreach with government entities between now and the final rule. Additionally, the EPA has determined that this action is not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments.
Nevertheless, the EPA is aware that there is substantial interest in this rule among small entities (
The EPA believes that this proposed rule may be of significant interest to state and local governments due to its relationship with the Clean Power Plan EGs. Therefore, the EPA has determined that consultations with state and local governments conducted during the Clean Power Plan EGs development process are also relevant to this proposed rule. Consistent with the EPA's policy to promote communications between the EPA and state and local governments, the EPA consulted with state and local officials early in the process of developing the Clean Power Plan EGs to permit them to have meaningful and timely input into its development. As described in the Federalism discussion in the preamble to the proposed standards of performance for GHG emissions from new EGUs (79 FR 1501; January 8, 2014), the EPA consulted with state and local officials in the process of developing the proposed standards for newly constructed EGUs. A detailed Federalism Summary Impact Statement (FSIS) describing the most pressing issues raised in pre-proposal and post-proposal comments will be forthcoming with the final Clean Power Plan EGs, as required by section 6(b) of Executive Order 13132. In the spirit of Executive Order 13132, and consistent with the EPA's policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on this
This proposed action has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law. The EGUs potentially impacted by this proposed rulemaking located on Indian reservations are primarily owned by private entities, and in one case, partially owned by an agency of the U.S. government. As a result, the tribes on whose areas of Indian country those units are located will not be directly impacted by any costs of complying with this proposed rulemaking incurred by the owners/operators of those units. There would only be tribal implications in regards to compliance costs associated with this proposed rulemaking in the case where a tribal government has an ownership interest in a potentially affected EGU. A tribal government could also incur costs in the event that it seeks and is given delegated authority to enforce the federal plan proposed in this rulemaking. The EPA has, nevertheless, offered consultation to the tribes on whose areas of Indian country the units are located. As part of its general outreach to tribes regarding this proposed rulemaking, the EPA received feedback from a number of tribes regarding the potential overall economic impact that both the proposed Clean Power Plan and a proposed federal plan rulemaking may have on them. In these instances, the EPA has reached out to these tribes and as part of the consultation on the Clean Power Plan engaged with them on their concerns regarding a potential federal plan.
The EPA has conducted consultation with tribes on the Clean Power Plan and the Supplemental Proposal for the Clean Power Plan and will offer all tribes consultation on this proposed action. The EPA held consultations with tribes on the Clean Power Plan in the fall of 2014 before the agency issued its Supplemental Proposal for Indian country and U.S. Territories. Additionally, the EPA held consultations for tribes shortly following the release of the supplemental proposal. The agency also held a public hearing on the supplemental proposal on November 19, 2014, in Phoenix, Arizona. At the public hearing the agency received oral comments from community members representing a number of tribes and a number of tribal officials. The agency also conducted consultations with tribes in the spring and summer of 2015. An overview of the consultations provided as part of the Clean Power Plan is available in section XII.F of the final EGs.
Additionally, the EPA engaged in meaningful dialogue with tribal stakeholders to obtain their feedback in the pre-proposal stages of this rulemaking. We provided an update on this proposed rulemaking on the May 28, 2015, National Tribal Air Association and the EPA Air Policy call. Staff attended the National Tribal Forum conference on May 20, 2015 and provided an overview of the Clean Power Plan and explained that the agency would be proposing a federal plan.
Consistent with previous rulemakings impacting the power sector, there is significant tribal interest in these rulemakings because of the potential indirect impacts that rules such as the Clean Power Plan and this proposed federal plan may have on tribes. The EPA specifically solicits additional feedback from tribal officials on all aspects of this proposed rulemaking, including whether tribes whose areas of Indian country contain affected EGU(s) are interested in developing their own plan implementing the final EGs. Additionally, tribal stakeholders will be included in the outreach that the agency will be conducting with those communities already overburdened by pollution, which are often low-income communities, communities of color, and indigenous communities. The actions that the agency will be taking are outlined in section IX of this preamble.
The EPA interprets EO 13045 (62 FR 19885; April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. This action is not subject to EO 13045 because it does not involve decisions on environmental health or safety risks that may disproportionately affect children. The EPA believes that the CO
This action, which is a significant regulatory action under EO 12866, is likely to have a significant effect on the supply, distribution, or use of energy. The EPA has prepared a Statement of Energy Effects for this action as follows. We estimate a 1 to 2 percent change in retail electricity prices on average across the contiguous United States in 2025, and a 22 to 23 percent reduction in coal-fired electricity generation as a result of this rule. The EPA projects that utility power sector delivered natural gas prices will increase by up to 2.5 percent in 2030. For more information on the estimated energy effects, please refer to the economic impact analysis for this proposal. The analysis is available in the RIA, which is in the public docket.
This proposed action involves technical standards. The EPA proposes to recognize ANSI accreditation under ISO 14065 for GHG validation and verification bodies as a component of accreditation of independent verifiers under both proposed federal plan approachs. The EPA also proposes that net energy output measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20.
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice (EJ). Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. The EPA defines EJ as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA has this goal for all communities and persons across this Nation. It will be achieved when everyone enjoys the
Leading up to this rulemaking the EPA summarized the public health and welfare effects of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the Administrator considered climate change risks to minority populations and low-income populations, finding that certain parts of the population may be especially vulnerable based on their characteristics or circumstances. Populations that were found to be particularly vulnerable to climate change risks include the poor, the elderly, the very young, those already in poor health, the disabled, those living alone, and/or indigenous populations dependent on one or a few resources. See sections X.F and X.G of this preamble, above, where the EPA discusses Consultation and Coordination with Tribal Governments and Protection of Children. The Administrator placed weight on the fact that certain groups, including children, the elderly, and the poor, are most vulnerable to climate-related health effects.
The record for the 2009 Endangerment Finding summarizes the strong scientific evidence in the major assessment reports by the U.S. Global Change Research Program, the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council of the National Academies that the potential impacts of climate change raise EJ issues. These reports concluded that poor communities can be especially vulnerable to climate change impacts because they tend to have more limited adaptive capacities and are more dependent on climate-sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particularly those impacted by degradation of natural and cultural resources within established reservation boundaries and threats to traditional subsistence lifestyles. Tribal communities whose health, economic well-being, and cultural traditions that depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. The 2009 Endangerment Finding record also specifically noted that Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities are already experiencing disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods and well-being.
The most recent assessments continue to strengthen scientific understanding of climate change risks to minority populations and low-income populations in the United States.
IPCC, 2014:
IPCC, 2014:
As the scientific literature presented above and as the 2009 Endangerment Finding illustrates, low-income populations and some communities of color are especially vulnerable to the health and other adverse impacts of climate change. The EPA believes that communities will benefit from this proposed federal plan because this action directly addresses the impacts of climate change by limiting GHG emissions through the establishment of CO
In addition to reducing CO
Additionally, as outlined in the community and EJ considerations section IX of this preamble, the EPA has taken a number of actions to help ensure that this action will not have potential disproportionately high and adverse human health or environmental effects on vulnerable communities. The EPA consulted its May 2015,
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations.
Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedure, Air pollution control.
For the reasons stated in the preamble, title 40, chapter I, parts 60, 62, and 78 of the Code of the Federal Regulations is amended as follows:
42 U.S.C. 7401
The revisions and additions read as follows:
(b) After receipt of a complete plan or complete plan revision, the Administrator will propose the plan or revision for approval or disapproval. The Administrator shall, within 12 months after the date on which the submission of a complete plan or complete plan revision is received, approve or disapprove such plan or revision, or each portion thereof.
(c) The Administrator shall promulgate a federal plan within 12 months after the date the Administrator:
(1) Finds the State failed to submit a complete plan or complete plan revision within the time prescribed; or
(3) Disapproves the State plan or plan revision or any portion thereof, as unsatisfactory because the requirements of this subpart and the applicable emission guidelines have not been met.
(d) The Administrator will promulgate the regulations under paragraph (c) of this section for all or a portion of a federal plan, with such modifications as may be appropriate, unless, prior to such promulgation, the State has adopted and submitted a plan or plan revision which the Administrator approves. After the promulgation of a federal plan, the Administrator may approve a State plan or plan revision or portion thereof and withdraw all or a portion of the federal plan.
(e)(1) Except as provided in paragraph (e)(2) of this section, regulations promulgated by the Administrator under this section will prescribe emission standards of the same stringency as the corresponding emission guideline(s) specified in the final guideline document published under § 60.22(a) and will require final compliance with such standards as expeditiously as practicable but no later than the times specified in the guideline document.
(g)
(2)
(i) A formal letter of submittal from the Governor or her designee requesting EPA approval of the plan or revision thereof;
(ii) Evidence that the State has adopted the plan in the state code or body of regulations. That evidence must include the date of adoption or final issuance as well as the effective date of the plan, if different from the adoption/issuance date;
(iii) Evidence that the State has the necessary legal authority under state law to adopt and implement the plan;
(iv) A copy of the actual regulation, or document submitted for approval and incorporation by reference into the plan. The submittal must be a copy of the official state regulation or document signed, stamped and dated by the appropriate state official indicating that it is fully enforceable by the State. The effective date of the regulation or document must, whenever possible, be indicated in the document itself. The State's electronic copy must be an exact duplicate of the hard copy. For revisions to the approved plan, the submittal must indicate the changes made (for example, by redline/strikethrough) to the approved plan;
(v) Evidence that the State followed all of the procedural requirements of the state's laws and constitution in conducting and completing the adoption and issuance of the plan;
(vi) Evidence that public notice was given of the proposed change with procedures consistent with the requirements of § 60.23, including the date of publication of such notice;
(vii) Certification that public hearing(s) were held in accordance with the information provided in the public notice and the State's laws and constitution, if applicable and consistent with the public hearing requirements in § 60.23;
(viii) Compilation of public comments and the State's response thereto; and
(ix) Such other criteria for completeness as may be specified by the Administrator under the applicable emission guidelines.
(3)
(i) Description of the plan approach and geographic scope;
(ii) Identification of each affected source, identification of emission standards for the affected sources, and monitoring, recordkeeping and reporting requirements that will determine compliance by each affected source;
(iii) Identification of compliance schedules and/or increments of progress;
(iv) Demonstration that the State plan submittal is projected to achieve emissions performance under the applicable emission guidelines;
(v) Documentation of state recordkeeping and reporting
(vi) Demonstration that each emission standard is quantifiable, non-duplicative, permanent, verifiable, and enforceable.
(4)
(i) The letter required by paragraph (g)(2)(i) of this section must request that EPA propose approval of the proposed plan by parallel processing;
(ii) In lieu of paragraph (g)(2)(ii) of this section the State must submit a schedule for final adoption or issuance of the plan;
(iii) In lieu of paragraph (g)(2)(iv) of this section the plan must include a copy of the proposed/draft regulation or document, including indication of the proposed changes to be made to the existing approved plan, where applicable; and
(iv) The requirements of paragraphs (g)(2)(v) through (ix) of this section do not apply to plans submitted for parallel processing. The exceptions granted in the preceding sentence apply only to EPA's determination of proposed action and all requirements of paragraph (g)(2) of this section must be met prior to publication of EPA's final determination of plan approvability.
(h)
(i)
(j)
(k)
42 U.S.C. 7401
(a) This subpart sets forth the requirements for the Clean Power Plan (CPP) CO
(b) The pollutants regulated by this subpart are greenhouse gases. The greenhouse gas limitations in this subpart are in the form of an emission standard for carbon dioxide (CO
(c)
(2) For the purposes of § 52.21(b)(50)(ii) of this chapter, with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” is considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter.
(3) For the purposes of § 70.2 of this chapter, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” is considered to be the pollutant that otherwise is “subject to regulation” as defined in § 70.2 of this chapter.
(4) For the purposes of § 71.2 of this chapter, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” is considered to be the pollutant that otherwise is “subject to regulation” as defined in § 71.2 of this chapter.
(a) You are subject to this subpart if you are the owner or operator of an affected electric generating unit (EGU) located within a State that has incorporated by reference this subpart as a State plan, or portion of a State plan, that has been approved by the Administrator and is effective under subpart UUUU of part 60 of this chapter, or if this subpart is promulgated and effective as a federal plan in your State under part 62 of this chapter.
(b) An affected EGU is any steam generating unit, IGCC, or stationary combustion turbine that meets the applicability requirements in §§ 60.5840(b) and 60.5845 of this chapter.
(a)
(2) The exemption under paragraph (a)(1) of this section will become effective on the first day of the compliance period immediately following the compliance period in which the retirement took effect. Within 30 days of the affected EGU's permanent retirement, the designated representative must submit a statement to the Administrator. The statement must state, in a format prescribed by the Administrator, that the affected EGU was permanently retired on a specified date and will comply with the requirements of paragraph (b) of this section.
(b)
(2) For a period of 5 years from the date the records are created, the owners and operators of an affected EGU exempt under paragraph (a) of this section must retain, at the facility that includes the unit, records demonstrating that the affected EGU is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the affected EGU is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of an affected EGU exempt under paragraph (a) of this section must comply with the requirements of the CO
(a)
(b)
(2) The emissions data determined in accordance with §§ 62.16345, 62.16360, and 62.16365 must be used to calculate allocations of CO
(c)
(ii) If total CO
(A) The owners and operators of the facility and each affected EGU at the facility must hold the CO
(B) The owners and operators of the facility and each affected EGU at the facility are subject to federal enforcement pursuant to sections 113(a) through (h), and section 304, of the Clean Air Act, and the United States, States, and other persons have the ability to enforce against violations (including if an affected EGU does not meet its emission standard based on its allowances) and secure appropriate corrective actions, and must pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act, and each ton of such excess emissions and each day of such compliance period will constitute a separate violation of this subpart and the Clean Air Act.
(2)
(ii) [Reserved]
(3)
(ii) A CO
(4)
(5)
(i) Such authorization must only be used in accordance with the CO
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(6)
(d)
(2) The applicable requirements of this subpart, as well as other terms or conditions necessary to ensure compliance with the applicable requirements, may be added to, or changed in, a title V permit using minor permit modification procedures in accordance with §§ 70.7(e)(2) and 71.7(e)(1) of this chapter, provided that such changes do not conflict with any existing terms of the permit. This paragraph explicitly provides that the addition of, or change to, an affected EGU's description as described in the prior sentence is eligible for minor permit modification procedures in accordance with §§ 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.
(3) No title V permit revision will be required for any allocation, holding, deduction, or transfer of CO
(e)
(2) Any provision of the CO
(f)
(a) Unless otherwise stated, any time period scheduled, under the CO
(b) Unless otherwise stated, any time period scheduled, under the CO
(c) Unless otherwise stated, if the final day of any time period, under the CO
The administrative appeal procedures for decisions of the Administrator under the CO
(a)(1) The Administrator will participate in the Clean Energy Incentive Program, established under subpart UUUU of part 60 of this chapter, on behalf of any state for which this subpart is promulgated as a federal plan under section 111(d) of the Clean Air Act. The Administrator will award, on behalf of each such state, early action allowances for generation and savings achieved in 2020 and/or 2021 that result from the following types of eligible renewable energy (RE) and demand-side energy efficiency (EE) projects:
(i) Metered wind power;
(ii) Metered solar power; and
(iii) Demand-side EE implemented in a low-income community.
(2) Eligible RE projects must commence construction, and eligible demand-side EE projects must
(b) Early action allowances will be distributed pursuant to a process to be prescribed by the Administrator, from an allowance set-aside equal to 300 million allowances for all states. This set-aside does not increase the total budget of allowances for the affected EGUs in the state subject to this subpart.
(c) The Administrator will match these early action allowances with additional matching allowances pursuant to a process to be prescribed by the Administrator. Matching awards will be made up to a limit equivalent to the state's pro rata share of 300 million short tons of CO
(d) The awards, including the matching award, will be executed as follows:
(1) For RE projects that generate metered MWh from wind or solar resources: for every two MWh generated, the project will receive a number of early action allowances the Administrator determines to be equivalent to one MWh from the set-aside under paragraph (b) of this section and a number of matching allowances the Administrator determines to be equivalent to one MWh from the match under paragraph (c) of this section.
(2) For EE projects implemented in low-income communities as determined by the Administrator solely for purposes of this subpart: for every two MWh in end-use demand savings achieved, the project will receive a number of early action allowances the Administrator determines to be equivalent to two MWh from the set-aside under paragraph (b) of this section and a number of matching allowances the Administrator determines to be equivalent to two MWh from the match under paragraph (c) of this section.
(a) The statewide mass-based emission goals with renewable energy set-asides and output-based set-asides for allocations of CO
(b) If implementing interstate trading, then the Administrator will use the sum of a covered group of States' mass-based emission goals as the aggregate mass-based emission goal.
(c) The renewable energy set-aside for each State covered by the federal mass-based emissions trading plan must reserve 5 percent from the State's annual allowances prior to allocation of that year's allowances to facilities. The renewable energy set-asides are specified in Table 2 of this subpart.
(d) The output-based set-aside for each State under this subpart, beginning in compliance period 2, must reserve a share of the State's annual allowances prior to allocation of that year's allowances to facilities as set forth in this paragraph (d). The output-based set-asides are specified in Table 3 of this subpart.
(e)(1) The Clean Energy Investment Program Set-Aside for each State covered under this subpart must contain an amount of allowances shown in Table 4 of this subpart, which must reserve a share of the State's annual allowances prior to allocation of that year's allowances to facilities as set forth in this paragraph.
(2) Allowances may be distributed from the set-aside for projects meeting the criteria of paragraph (e)(3) of this section, upon application of a project proponent that meets the requirements of § 62.16245(a), except as may be prescribed by the Administrator in a future action. In order to receive a distribution, the project proponent must establish a general account in the tracking system as provided in § 62.16320(c).
(3) Projects eligible for distribution of allowances from this set-aside must meet each of the criteria in paragraphs (e)(3)(i) through (iii) of this section. All categories of resources other than those listed in paragraphs (e)(3)(iii)(A) and (B) of this section, and all provisions of this subpart relating to such resources, are not available or applicable in States where this subpart has been promulgated as a federal plan pursuant to section 111(d)(2) of the Clean Air Act.
(i) The project was constructed or implemented on or after the signature date of the final rule promulgating subpart UUUU of part 60 of this chapter;
(ii) The creditable generation or energy savings from the project must occur in calendar years 2020 or 2021; and
(iii) Generation or energy savings must be from one of the following types of sources capable of revenue-quality metering:
(A) Onshore wind;
(B) Solar; or
(C) Demand-side EE.
(a)
(2) Notwithstanding paragraph (a)(1) of this section, if an affected EGU which is provided an allocation does not operate for 2 consecutive calendar years, then such affected EGU will not be allocated the CO
(3) Notwithstanding paragraph (a)(1) of this section, if an affected EGU provided an allocation issued by the Administrator in notice of data availability or through this subpart (if applicable) is modified or reconstructed such that it is no longer subject to this subpart, then such affected EGU will not be allocated the CO
(b)
(ii) By December 1, 2021 and December 1 of each year thereafter, the Administrator will calculate and allocate the CO
(2)
(ii) By November 1 of the first year of each compliance period beginning in 2025, and each compliance period thereafter, the Administrator will calculate and allocate the CO
(c)
(i)(A) The recipient is not actually an affected EGU under § 62.16210 as of January 1, 2022 and is allocated CO
(B) The recipient is not located as of January 1 of the compliance period in the State from whose CO
(ii) The recipient is not actually an affected EGU under § 62.16210 as of January 1 of such compliance period and is allocated CO
(2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such CO
(3) If the Administrator already recorded such CO
(4) If the Administrator already recorded such CO
(5)(i) With regard to the CO
(A) Transfer such CO
(B) If the State has a state allowance distribution methodology approved under subpart UUUU of part 60 of this chapter covering such compliance period, then include such CO
(ii) With regard to the CO
(A) Transfer such CO
(B) If the State has a state allowance distribution methodology approved under subpart UUUU of part 60 of this chapter covering such compliance period, then include such CO
(iii) With regard to the CO
(a)(1)
(2)
(i) The resource must be a renewable energy resource that falls into one of the following categories of resources: on-shore utility scale wind, solar, geothermal power, or utility scale hydropower.
(ii) The resources must only include resources which increased new installed electrical generation nameplate capacity, or new electrical savings measures installed or implemented after January 1, 2013. If a resource had a nameplate capacity uprate, then set-aside allowances may be issued only for the difference in generation between the uprated nameplate capacity and its nameplate capacity prior to the uprate. Set-aside allowances must not be issued for generation for an uprate that followed a derate that occurred on or after January 1, 2013. A resource that is relicensed or receives a license extension is considered existing capacity and is not an eligible resource, unless it receives a capacity uprate as a result of the relicensing process that is reflected in its relicensed permit. In such a case, only the difference in nameplate capacity between its relicensed permit and its prior permit is eligible to be issued set-aside allowances.
(iii) The resource must be located in the mass-based State for which the set-aside has been designated.
(iv) The resource must be connected to, and delivers energy to or saves electricity, on the electric grid in the contiguous United States.
(v) The resource must not have received emission rate credits (ERCs) for any period of time for which it receives set-aside allowances.
(3)
(i) Eligibility application. To receive set-aside allowances, an authorized account representative of an eligible resource must submit an eligibility application to the Administrator that demonstrates that the requirements of paragraph (a)(2) of this section are met and demonstrates that the following requirements are met:
(A) Identification of the authorized account representative of the eligible resource, including the authorized account representative's name, address, email address, telephone number, and allowance tracking system account number; and
(B) Identification of the eligible resource(s), including the physical location of the eligible resource; contact information for the owner or operator of the eligible resource, if different from the authorized account representative and designated representative; generator prime mover and technology type; generator nameplate capacity (if applicable); generator category (
(ii) Renewable energy providers must open a general account per the requirements in § 62.16320(c), and submit a project application for renewable energy set-aside allowances to the Administrator by June 1 of the year prior to the generation year for which set-aside allowances are requested. Providers may update submitted projections for future generation years, these projections must be received by June 1 of the year prior to the generation year in question. The project application must contain the following information:
(A) Projection of the project's annual renewable energy generation in MWh.
(B) Documentation of the methodology, data facilities, and assumptions used to project the project's annual renewable energy generation.
(C) A certification that the eligibility application has only been submitted to the Administrator or pursuant to an EPA-approved multi-State approach where States are providing for joint issuance of allowances pursuant to the authority in their individual State plans.
(D) A evaluation, measurement, and verification (EM&V) plan.
(E) A verification report from an accredited independent verifier who meets the requirements of § 62.16275 and § 62.16280. While considered a part of the eligibility application, the verification report must be submitted separately by the accredited independent verifier to the Administrator.
(F) An authorization that provides for the following: the Administrator may inspect (including a physical inspection of the eligible resource and its meter) and/or audit the eligible resource at any time and verify that the eligible resource and the EM&V plan have been implemented as described in the eligibility application.
(G) The following statement, signed by the authorized account representative of the eligible resource:
(H) Any other information required by the Administrator.
(4)
(i) A measurement and verification (M&V) report.
(ii) A verification report from an accredited independent verifier that meets the requirements of § 62.16275 and § 62.16280. While considered a part of the M&V report, the verification report must be submitted separately by the accredited independent verifier to the Administrator.
(5)
(i) The Administrator will distribute renewable energy set-aside allowances for a generation year with the number of allowances distributed to each project prorated according to its percentage of the total approved projected MWhs for that State that the project represents.
(ii) If in the previous generation year, the project did not reach the MWhs projected, then the unfulfilled MWhs will be subtracted from that provider's projected generation eligible for the set-aside pool.
(iii) If the unfulfilled MWhs from a previous year exceed the projected hours for the generation year, then the Administrator will carry over the deficit and subtract from the projected generation in subsequent years until there is no deficit. If this deficit is greater than 10 percent in a particular year, then the provider will need to provide an explanation to the Administrator of the deficit, and will be required to reevaluate their projections for future years. If such deficits continue through all 3 years of the first or second compliance period, then the Administrator will disqualify the provider from receiving future set-asides for the following compliance period.
(6)
(7)
(b)(1)
(2)
(i) The affected EGU must be a natural gas combined cycle unit;
(ii) The affected EGU must be located in the mass-based State for which the set-aside has been designated; and
(iii) The affected EGU's average capacity factor in the preceding compliance period was above 50 percent based on net summer capacity and net generation.
(3)
(i) The Administrator will calculate the amount of allowances an eligible EGU receives from the output-based set-aside as the unit's average net generation in the preceding compliance period over 50 percent multiplied by the allocation rate of 1,030 lb/MWh-net.
(ii) If the amount of total allowances exceeds the size of the State's set-aside, then the allowances will be allocated to the State's eligible generation on a pro-rata basis.
(iii) The Administrator will provide notice of the net summer capacity and net generation data used, and the resulting allocations by August 1 of the first year of each compliance period beginning in 2025. The notice of the net summer capacity and net generation data used, and the resulting allocations, must allow 30 days for public comment on the data and allocations, until August 31 of the same year.
(iv) The Administrator will provide notice of the final set-aside allocations by November 1 of the same year.
(4)
(5)
(a) If an eligible resource is found to not meet the requirements of § 62.16260 in the CO
(b) Any instance of intentional misrepresentation in an eligibility application or M&V report may be cause for revocation of the qualification status of an eligible resource.
(c) Repeated instances of error or misstatement of MWh of electricity generation or savings in submitted M&V reports, or in any other submissions may be cause for the Administrator to revoke the eligibility of an eligible resource to be issued set-aside allowances.
(d) In the event of an intentional misrepresentation, or repeated instances of error or misstatement, in program submissions, by the authorized account representative of the eligible resource, the Administrator may prohibit the eligible resource from any further eligibility to be issued allowances. In addition, the provisions of § 62.16255(a) through (d) may apply.
(a) In the event of error or misstatement of quantified MWh of electricity generation or savings in a previous M&V report for which set-aside allowances have been issued, the Administrator may adjust the number of set-aside allowances issued in a subsequent reporting period to address the error or misstatement, by subtracting a number of MWh from the quantified and verified MWh in the M&V report for the subsequent reporting period. In the event that an error or inadvertent misstatement occurs in a final M&V report for an eligible resource, for which set-aside allowances have been issued, the provisions of paragraph (b) of this section will apply.
(b) In the event of error or misstatement of quantified MWh of electricity generation or savings in the final M&V report for an eligible resource, for which set-aside allowances have been issued, the Administrator will revoke set-aside allowances from the general account held by the authorized account representative of the eligible resource, in an amount necessary to correct the error or misstatement. In the event that the general account of the eligible resource holds an insufficient number of set-aside allowances to correct the error or misstatement, the authorized account representative must submit to the Administrator within 30 days a number of set-aside allowances necessary to correct the error or misstatement. Failure to meet this requirement will result in prohibition of the authorized account representative for the eligible resource from further participation in the program, unless reauthorized at the discretion of the Administrator.
(c) The Administrator may freeze the general account held by an authorized account representative of an eligible resource at any time, for cause, if the Administrator determines set-aside allowances have been improperly issued, based on a misrepresentation or misstatement in an eligibility application or M&V report. The Administrator may also freeze the general account of an authorized account representative of an eligible resource pending investigation of potential misrepresentation, error, or misstatement in an eligibility application of an eligible resource, or in an M&V report for which set-aside allowances have been issued. Freezing a general account will prevent transfer of allowances out of the account.
(d) If set-aside allowances are issued for an eligible resource that is found to be ineligible, then the Administrator may take the actions in paragraphs (d)(1) through (3) of this section.
(1) Freeze the general account of the authorized account representative for an eligible resource, preventing any transfers of allowances out of the account.
(2) Revoke or deduct allowances held in the general account of the authorized account representative for an eligible resource, in a number equal to the number of allowances issued for the ineligible eligible resource.
(3) In the event that the general account of the eligible resource holds a number of allowances less than the number of set-aside allowances issued for the ineligible eligible resource, the delegated representative of an eligible resource must submit to the Administrator within 30 days a number of allowances necessary to fully account for all allowances issued for the ineligible eligible resource. Failure to meet this requirement will result in prohibition of the eligible resource from further participation in the program, unless reauthorized at the discretion of the Administrator.
(e) The Administrator may temporarily or permanently suspend issuance of set-aside allowances for an eligible resource, for the following reasons in paragraphs (e)(1) through (3) of this section.
(1) Pending investigation of potential misrepresentation, error, or misstatement in an M&V report, for which set-aside allowances have been issued, or the eligibility status of an eligible resource.
(2) In the case of repeated error or misstatements in submitted M&V reports.
(3) In the case of an intentional misrepresentation in a submitted M&V report.
(a)
(b)
(c)
(1) For a nuclear energy resource or a renewable energy resource with a nameplate capacity of 10 kW or more and for a renewable energy resource with a nameplate capacity of less than 10 kW for which metered data are available, each EM&V plan must specify that the requirements in paragraphs (c)(1)(i) through (vi) of this section must be met.
(i) The generation data are physically measured on a continuous basis using a revenue-quality meter, which means a meter used by a control area operator for financial settlements, or a meter that meets the American National Standards Institute No. C12.20., Code for Electricity Metering, metering accuracy standards, or a meter that meets an alternative equivalent standard that has been approved in advance of its use to measure generation pursuant to this regulation by the EPA.
(ii) The generating data are measured at the generator's bus bar, or, for a renewable energy resource with a nameplate capacity of less than 10 kW that is interconnected behind an individual business or household meter, the generating data were measured at the AC output of the inverter and adjusted to reflect the only energy delivered into either the transmission or distribution grid at the generator bus bar and not any energy used on-site at the generator.
(iii) The generation data from only one eligible resource generating unit may be associated with each meter, and generation data may not be aggregated, unless all the following provisions are met:
(A) All of the generating units have the same essential generation characteristics;
(B) All of the generating units are located in the same State;
(C) The nameplate capacity of the individual units being aggregated is each less than 150 kW, and units collectively do not exceed a total nameplate capacity of 1 MW when aggregated, or alternative requirements approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan or M&V report is submitted; and
(D) The generation data are measured by the same type of meter that is subject to the same maintenance and quality assurance procedures.
(iv) The generation data are collected electronically and telemetered from the generator to its control area operator and verified through a control area energy accounting or settlement process which occurs at least monthly, unless the generation unit does not go through a control area operator, in which case the generation data must be collected by manual meter readings conducted by an independent verifier that is either not affiliated with the owner or operator of the qualifying renewable energy generating resource or is precluded pursuant to the relevant State plan from the ability to transfer or retire set-aside allowances issued to that qualifying renewable energy generating resource or, if the generating unit is less than 10 kw and does not generate enough electricity to enable monthly reporting, then the data may be self-reported and reported no less than annually.
(v) The generation data serve a load that otherwise would have been served by the grid if not for the generator. Specifically:
(A) Set-aside allowances shall not be issued for energy generation used to supply the ancillary equipment used to operate a generating station or substation (“station service”) or parasitic load on the generator's side of the point of interconnection; and
(B) For generators interconnected to transmission systems and with on-site loads other than station service drawing generation before the metering point, set-aside allowances may be issued for on-site load, if the owner or operator of the eligible resource can demonstrate that the metering used is capable of distinguishing between on-site load and station service.
(vi) Any other requirements approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan is submitted.
(2) For a renewable energy resource with a nameplate capacity of less than 10 kW and that does not have a meter, each EM&V plan must require that the following requirements in paragraphs (c)(2)(i) through (vii) of this section are met.
(i) Metered data are unavailable.
(ii) At least 1 MW of net energy output is generated to the distribution or transmission system over a continuous 365-day period.
(iii) The generation data may not be aggregated, unless the following provisions are met:
(A) All of the generating units have the same essential generation characteristics;
(B) All of the generating units are located in the same State;
(C) The nameplate capacity of the individual units being aggregated is each less than 150 kW, and units collectively do not exceed a total nameplate capacity of 1 MW when aggregated, or alternative requirements approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan or M&V report is submitted; and
(D) The generation data are measured by the same generation estimating software or algorithms.
(iv) The generation data are measured on at least a monthly basis using generation estimating software or algorithms that are based on an on-site inspection prior to interconnection and a resource study (wind, shading, solar irradiance, depending on the resource), or engineering information that takes into account the capacity, age, and type of qualifying energy generating resource, and all input parameters and assumptions must be clearly delineated, or if the generating unit does not generate enough electricity to enable monthly reporting, then the data may be reported no less than annually.
(v) The generation data are self-reported to the distribution utility through an electronic internet-based portal with software that reports total and hourly generation.
(vi) The generation data serves a load that otherwise would have been served by the grid if not for the generator. The set-aside allowance is only based on generation transferred from the eligible resource to the transmission or distribution grid, and is not based on the generation used on-site by the customer.
(vii) Any other requirements approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan is submitted.
(3) For qualified biomass feedstocks used, in addition to the requirements of paragraph (c)(1) or (2) of this section, whichever section is applicable, each EM&V plan must demonstrate that the requirements approved by the EPA for that biomass feedstock, and its associated biogenic CO
(4) For a waste-to-energy resource, in addition to the requirements of paragraph (c)(1) or (2) of this section, as applicable, and paragraph (c)(3) of this section, each EM&V plan must specify:
(i) The total net energy generation from the resource in MWh;
(ii) The method for determining the specific portion of the total net energy output from the resource that is related to the biogenic portion of the waste; and
(iii) The net energy output is measured with the relevant method approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan is submitted demonstrates that the requirements approved by the EPA in connection with that State plan have been met.
(5) For a combined heat and power unit, in addition to the requirements of paragraphs (c)(1) or (2) of this section,
(i) If the combined heat and power unit has an electric generating capacity greater than 25 MW, then the EM&V plan must meet the requirements that apply to an affected EGU under § 62.16540 of this subpart.
(ii) If the combined heat and power unit has an electric generating capacity less than or equal to 25 MW and greater than 1 MW, and it uses only natural gas and/or distillate fuel oil, then the EM&V plan must meet the low mass emission unit CO
(iii) If the combined heat and power unit has an electric generating capacity less than or equal to 25 MW and greater than 1 MW, and it uses anything other than only natural gas and/or distillate fuel oil, then the EM&V plan must meet the low mass emission unit CO
(iv) If the combined heat and power unit has an electric generating capacity less than or equal to 1 MW the unit must keep monthly cumulative recordings of useful thermal output and fossil fuel input along with the determination of baseline thermal source efficiencies based on manufacturer data. For CHP units that directly serve on-site end-use electricity loads, avoided transmission and distribution (T&D) system losses can be assessed as is commonly practiced with demand-side EE.
(6) For electricity savings that avoid a transmission and distribution loss, each EM&V plan must measure the transmission and distribution loss based on the lesser of 6 percent of the site-level electricity savings measured at the end use meter or the statewide annual average transmission and distribution loss rate (expressed as a percentage) from the most recent year that is published in the US EIA State Electricity Profile expressed as a percentage. No other transmission and distribution loss factors may be used in calculating the electricity savings, including measures such as conservation voltage reduction and volt/VAR optimization.
(7) Each EM&V plan for an EE program, EE project, or EE measure must specify how each of the requirements in paragraphs (c)(7)(i) through (x) of this section will be met in quantifying the electricity savings from that EE program, EE project, or EE measure.
(i) All electricity savings must be quantified on an ex-post basis, which means after the electricity savings have occurred, or on a real-time basis, which means at the time the electricity savings are occurring. Electricity savings must not be quantified on an ex-ante basis, which means estimates of MWh savings that are generated prior to implementing the subject EE program, EE project, or EE measure, and that are not quantified using EM&V methods and procedures.
(ii) All electricity savings must be quantified and verified based on methods and procedures detailed in an industry best-practice EM&V protocol or guideline. Each EM&V plan must include a demonstration of how the best-practice protocol or guideline was selected and will be applied to the specific EE program, EE project, or EE measure covered in the EM&V plan, and an explanation of why that particular protocol or guideline was selected. Protocols and guidelines are considered to be best practice if they:
(A) Have gone through a rigorous and credible peer review process that shows the applicable methods to be valid through empirical testing; and
(B) Have been accepted and approved for use by identifiable state regulatory commissions. Examples of such protocols and guidelines that may be provided in EM&V guidance issued by the Administrator will be acceptable.
(iii) All electricity savings must be quantified as the difference between the observed electricity use and a common practice baseline (CPB), which is the equipment that would typically have been installed—or that a typical consumer or building owner would have continued using—in a given circumstance (
(A) Characteristics of the EE program, EE project, or EE measure;
(B) The delivery mechanism used to implement the EE program, EE project, or EE measure (
(C) Local consumer and market characteristics;
(D) Applicable building energy codes and standards and average compliance rates; and
(E) The method applied: project-based measurement and verification (PB-MV), comparison group approaches, or deemed savings.
(iv) All electricity savings must be quantified by applying one or more of the following methods: PB-MV, comparison group approaches, or deemed savings.
(A) If a comparison group approach is used, then the EM&V plan must quantify electricity savings by taking the difference between a comparison group's electricity use and the electricity use of EE program participants. Comparison group approaches may include randomized control trials and quasi-experimental methods, as described in industry best-practice protocols and guidelines. Examples of such protocols and guidelines provided in EM&V guidance that may be issued by the Administrator will be acceptable.
(B) If deemed savings are used, then the EM&V plan must specify that the deemed savings values will only be used for the specific EE measure for which they were derived. The EM&V plan must also specify the name and Web address of the technical reference manual (TRM) in which all deemed electricity savings values will be documented. Prior to use in an EM&V plan, all TRMs must undergo a review process in which the public, stakeholders, and experts are invited—with adequate advance notification (via the internet and other social media)—to provide comment, have at least 2 months to provide comment, and in which all such comments and associated responses are made publicly available. All TRMs must also be publicly accessible over the full period of time in which they are being used in conjunction with an EM&V plan for the purpose of quantifying savings, and must be subsequently updated in the same manner at least every 3 years. The TRM must indicate, for each subject EE measure, the associated electricity savings value, the conditions under which the value can be applied (including the climate zone, building type, manner of implementation, applicable end uses, operating conditions, and effective useful life), and the manner in which the electricity savings value was quantified, which must include applicable engineering algorithms, source documentation, specific assumptions, and other relevant
(v) All EE programs, EE projects, or EE measures must be quantified at time intervals (in years) sufficient to ensure that MWh savings are accurately and reliably quantified. Such time intervals must be specified and explained in the EM&V plan. Factors that must be taken into consideration when determining the appropriate time interval include the characteristics of the specific EE program, EE project, or EE measure, expected variability in electricity savings (where greater variability necessitates more frequent quantification), the expected scale and magnitude of the electricity savings (where greater quantities of savings necessitate more frequent quantification), and the experience implementing and quantifying savings from the resource (where less experience—for example, with new and innovative EE program types—necessitates more frequent quantification). The time intervals must end no sooner than the last day of the effective useful life of the EE program, EE project, or EE measure, and must last no longer than:
(A) Every 4-year intervals for building energy codes and product standards;
(B) Every 1, 2 or 3 years for public or consumer-funded EE program, EE project, or EE measure, as relevant for the type of EE program, EE project, or EE measure and factors listed in paragraph (c)(7)(v) of this section; and
(C) Annually for commercial and industrial projects, unless the resource provider can provide a reasonable justification in the EM&V plan for why an annual time interval is not feasible, and can additionally explain how the accuracy and reliability of savings values will not be lessened.
(vi) EM&V plans must specify and document how the EM&V components in paragraphs (c)(7)(vi)(A) through (E) of this section will be analyzed, considered, or otherwise addressed in the quantification and verification of electricity savings.
(A) The effects of changes in independent factors on reported electricity savings (
(B) The effective useful life (EUL) or duration of time the EE measure is anticipated to remain in place and operable with the potential to save electricity, which must be based on the application of EM&V methods, an industry best-practice persistence study, deemed estimates of effective useful life, or a combination of all three.
(C) The potential sources of double counting, and the associated steps for avoiding and correcting for it, such as:
(D) The EE savings verification approaches for ensuring that EE measures have been properly installed, are operating as intended, and therefore have the potential to save electricity, including how verification will be carried out within the first year of implementation of the EE program, EE project, or EE measure using best-practice approaches, such as physical inspections at a customer's premises, phone and mail surveys, and reviews of sales receipts and other documentation. If such approaches are documented in EM&V guidance issued by the Administrator, they will be treated as acceptable.
(E) The interactive effects of EE programs, EE projects, or EE measures on electricity usage, which are increases or decreases in electricity usage at an end-use facility or premises that occurs outside of specific end-uses(s) targeted by the EE program, EE project, or EE measure (
(vii) The EM&V plan must specify how the accuracy and reliability of the electricity savings of the EE program, EE project, or EE measure will be assessed, and must discuss the rigor of the method selected to quantify the electricity savings. It must also discuss the approaches that will be used to control all relevant types of bias and to minimize the potential for systematic and random error, as well as the program- or project-specific circumstances in which such bias and error are likely to arise. Approaches to minimizing bias and error are provided in the EM&V guidance that may be issued by the Administrator will be acceptable.
(viii) If sampling will be used to quantify the electricity savings from an EE program, then the MWh estimates derived from sampling must have at least 90 percent confidence intervals whose end points are no more than +/−10 percent of the estimate, and the statistical precision of the associated estimates must be specified in the EM&V plan.
(ix) All data sources and key assumptions used to quantify electricity savings must be described in the EM&V plan.
(x) Any additional information necessary to demonstrate that the electricity savings were appropriately quantified and verified. Approaches to quantifying and verifying savings from several EE program and EE project types that are provided in EM&V guidance that may be issued by the Administrator will be acceptable.
(d) You must ensure that any EM&V plan submitted pursuant to this subpart includes the following certification:
(1) “I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) [Reserved]
(a)
(b)
(1) For the first M&V report submitted, documentation that the electricity-generating resources, electricity-saving measures, or practices were installed or implemented consistent with the description in the approved eligibility application required in § 62.16245(a)(3).
(2) For each M&V report submitted:
(i) Identification of the time period covered by the M&V report;
(ii) A description of how relevant quantification methods, protocols, guidelines, and guidance specified in the EM&V plan were applied during the reporting period to generate the quantified MWh of generation or MWh of electricity savings;
(iii) Documentation (including data) of the energy generation and/or electricity savings from any activity, project, measure, or program addressed in the EM&V report, quantified and verified in MWh for the period covered by the M&V report, in accordance with its EM&V plan, and based on ex-post energy generation or savings;
(iv) Documentation of any change in the energy generation or savings capability of the eligible resource during the period covered by the M&V report and the date on which the change occurred, and either certification that the eligible resource continued to meet all eligibility requirements during the reporting period covered by the M&V report or disclosure of any material changes to the eligible resource from the description of the eligible resource in the approved eligibility application, which must include any change in the energy generation (
(v) Documentation of any change in ownership interest of the qualifying eligible resource (including the date of the change).
(c) You must ensure that any M&V report submitted pursuant to this subpart includes the following certification:
(1) “I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) [Reserved]
(a) A verification report included as part of an eligibility application or an M&V report must meet the requirements of paragraph (b) of this section (for the eligibility application verification report) and paragraph (c) of this section (for the M&V report verification report) and include the following:
(1) A verification statement that sets forth the findings of the accredited independent verifier, based on the verifier's assessment of the information and data in the eligibility application or M&V report that is the subject of the verification report, including an assessment of whether the eligibility application or M&V report contains any material misstatements or material data discrepancies, and whether the submittal conforms with applicable regulatory requirements. The verification statement must clearly identify how levels of assurance and materiality are defined as part of the verifier assessment.
(2) The following statement, signed by the accredited independent verifier: “I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my personal knowledge and/or inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(b) A verification report included as part of an eligibility application must, at a minimum, describe the review conducted by the accredited independent verifier and verify each of the following:
(1) The eligibility of the eligible resource to be issued set-aside allowances pursuant to this regulation, in accordance with § 62.16245(a), including an analysis of the adequacy and validity of the information submitted by the authorized account representative to demonstrate that the eligible resource meets each applicable requirement of § 62.16245;
(2) The eligible resource is not duplicative of a resource used to meet emission standards or a state measure in another approved State plan;
(3) The eligible resource exists or the operation or activity will be implemented in the manner specified in the eligibility application;
(4) That the EM&V plan meets the requirements of § 62.16260;
(5) Disclosure of any mandatory or voluntary programs to which data is reported relating to the eligible resource (
(6) Any other information required by the Administrator or that the accredited independent verifier finds, in its professional opinion, is necessary to assess the adequacy and validity of information and data supplied by the authorized account representative.
(c) A verification report included as part of an M&V report must, at a minimum, describe the review conducted by the accredited independent verifier and verify the information specified in paragraphs (c)(1) through (3) of this section.
(1) The adequacy and validity of the information and data submitted in the submittal by the authorized account representative to quantify eligible MWh of electric generation or electricity savings during the period for which the authorized account representative seeks issuance of set-aside allowances, as well as all supporting information and data identified in the EM&V plan and M&V report. This analysis must include a quality assurance and quality control check of the data and ensure that all generation or savings data is within a technically feasible range for that specific eligible resource.
(i) For metered generation, the data validity check must compare reported electricity generation to an engineering estimate of the maximum generation potential of the qualified renewable energy resource, based on, at a minimum, its maximum nameplate capacity in MW and the number of days since the prior cumulative meter reading was entered in the allowance tracking system. If the data entered exceeds the estimated technically feasible generation, then the reported data and the estimate must be analyzed in the verification report.
(ii) For all electricity generated or saved, the accredited independent verifier must describe the likely source of any data discrepancy and determine
(2) The M&V report meets the requirements of § 62.16265.
(3) Any other information required by the Administrator or that the accredited independent verifier finds, in its professional opinion, is necessary to assess the adequacy and validity of information and data supplied by the authorized account representative.
(a) Only Administrator-accredited independent verifiers may provide a verification report for an eligibility application or M&V report.
(b) Applications for accreditation must follow a procedure and form specified by the Administrator which includes a demonstration by the verifier that it meets the requirements in paragraph (c) of this section.
(c) Independent verifiers must meet each of the requirements in paragraphs (c)(1) through (6) of this section to be accredited.
(1) Independent verifiers must have the skills, experience, resources (personnel and otherwise) to provide verification reports, including the following:
(i) Appropriate technical qualification (professional engineer or otherwise) to evaluate the eligible resource for which the independent verifier is seeking accreditation, which may include ANSI accreditation under ISO 14065 for GHG validation and verification bodies;
(ii) Appropriate auditing and accounting qualifications for financial and non-financial data monitoring, auditing, and quality assurance and quality control to evaluate the eligible resource for which the independent verifier is seeking accreditation;
(iii) Knowledge of the requirements of the Administrator's CO
(iv) Knowledge of the eligible resource categories for which the independent verifier is seeking accreditation, including relevant aspects of the design, operation, and related energy generation or electricity savings monitoring and reporting approaches for such eligible resources; and
(v) Capability to perform key verification activities, such as development of a verification report; site visits; review and recalculation of reported data; review of data management systems; review of quantification methods used in accordance with an approved EM&V plan; preparation of a verification opinion, list of findings, and verification report; and internal review of the verification findings and report.
(2) Independent verifiers must document, in the application for accreditation, the independent verifiers that will provide verification services, including lead verifiers, key personnel and any contractors or subcontractors (collectively, accredited independent verification team) and demonstrate that they meet the requirements of paragraph (c)(1) of this section. Once accredited, only the accredited independent verification team identified in the accreditation application and accredited by the State may provide a verification report.
(3) An independent verifier must specify the eligible resource categories for which it is seeking accreditation, and an accredited independent verifier may only provide verification services related to an eligible resource category for which it is accredited.
(4) Prospective independent verifiers must meet the requirements of § 62.16280(d) through (f) and demonstrate that they have in place adequate systems and protocols to identify, disclose and avoid potential conflicts of interest.
(5) An accredited independent verifier must not be debarred, suspended, or proposed for debarment pursuant to the Government-wide Debarment and Suspension regulations, 40 CFR part 32 of this chapter, or the Debarment, Suspension and Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4.
(6) An accredited independent verifier must maintain, for its employees, and ensure the maintenance of, for any parties that it employs, professional liability insurance, as defined in 31 CFR 50.5(q), through an insurance provider that possesses a financial strength rating in the top four categories from either Standard & Poor's or Moody's, specifically, AAA, AA, A or BBB for Standard & Poor's, and Aaa, Aa, A, or Baa for Moody's. Any entity covered by this paragraph must disclose the level of professional liability insurance they possess when entering into contracts to provide verification services pursuant to this regulation.
(d)
(1) Accredited independent verifiers must meet the requirements of § 62.16280 when providing verification services for an authorized account representative.
(2) The instances specified in § 62.16280(d) are cause for revocation of a verifier's accreditation.
(a) Accredited independent verifiers must not provide verification services for any eligible resource for which it has a conflict of interest (COI), which means:
(1) Accredited independent verifiers must have, or have had, no direct or indirect financial interest in, or other financial relationships with, an eligible resource, or any prospective eligible resource, for which they seek to provide a verification report;
(2) Accredited independent verifiers must have, or have had, no direct or indirect organizational or personal relationships with an eligible resource, that would impact their impartiality in assessing the validity and accuracy of the information in an eligibility application or M&V report;
(3) Accredited independent verifiers must have, or have had, no role in the development and implementation of an eligible resource for which an authorized account representative seeks issuance of set-aside allowances, beyond the provision of verification services;
(4) Accredited independent verifiers must not be compensated, financially or otherwise, directly or indirectly, on the basis of the content of its verification report (including eligibility approval of an eligible resource, the quantified and verified MWh in an M&V report, set-aside allowance issuance, or the number of set-aside allowances issued);
(5) Accredited independent verifiers must not own, buy, sell, or hold set-aside allowances, or other financial derivatives related to set-aside allowances, or have a financial relationship with other parties that own, buy, sell, or hold set-aside allowances or other related financial derivatives;
(6) An accredited independent verifier must not be incapable of providing an impartial verification report for any other reason; and
(7) An accredited independent verifier must ensure that the subject of any verification report must not have the opportunity to review or influence any draft or final verification report before its submittal to the Administrator, and the accredited independent verifier must share any drafts of its reports with the Administrator at the same time as it shares them with the subject of the report.
(b) A contract with an eligible resource for the provision of verification services will not constitute a COI.
(c) Verification reports must include an attestation by the accredited independent verifier that it evaluated
(d) Prior to engaging for the provision of verification services, an accredited independent verifier must demonstrate that it has no COI related to the eligible resource, as specified in paragraph (a) of this section. If a COI is identified for a person or persons within an accredited independent verifier for a specific subject or verification, in accordance with paragraphs (e) and (f) of this section, then an accredited independent verifier may propose to the Administrator steps that will be taken to eliminate the COI, which include prohibiting the person or persons with the conflict from any involvement in the matter subject to the conflict, including verification services, access to information related to the verification services, access to any draft or final verification reports, any communications with the person(s) conducting the verification services. In no instance shall an accredited independent verifier engage in verification services for an eligible resource without the approval of the Administrator.
(e) Prior to engaging in verification services and writing a verification report, an accredited independent verifier must disclose to the Administrator all information necessary for the Administrator to evaluate a potential COI (including information concerning its ownership, past and current clients, related entities, as well as any other facts or circumstances that have the potential to create a COI).
(f) Accredited verifiers have an ongoing obligation to disclose to the Administrator any facts or circumstances that may give rise to a COI as defined in paragraph (a) of this section.
(g) The Administrator may reject a verification report from an accredited independent verifier, if the Administrator determines that the accredited independent verifier has a COI as defined in paragraph (a) of this section. If the Administrator rejects an accredited independent verifier report for such reasons, then the eligibility application or M&V report submittal shall be deemed incomplete and set-aside allowances must not be issued pursuant to it.
(a) The Administrator may revoke the accreditation of an independent verifier at any time for cause, including for the reasons specified in paragraphs (a)(1) through (4) of this section.
(1) Failure to fully disclose any issues that may lead to a COI with respect to an eligible resource, or other related entity, in accordance with § 62.16280(d) through (f).
(2) The accredited independent verifier is no longer qualified to provide verification services.
(3) Negligence in the conduct of verification activities, or neglect of responsibilities pursuant to the requirements of §§ 62.16270, 62.16275, and 62.16280.
(4) Intentional misrepresentation of data in a verification report.
(b) [Reserved]
(a) Except as provided under § 62.16300, each facility, including all affected EGUs at the facility, shall have one and only one designated representative, with regard to all matters under the CO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the facility and all affected EGUs at the facility and must act in accordance with the certification statement in § 62.16305(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 62.16305:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the facility and each affected EGU at the facility in all matters pertaining to the CO
(ii) The owners and operators of the facility and each affected EGU at the facility shall be bound by any decision or order issued to the designated representative by the Administrator regarding the facility or any such affected EGU.
(b) Except as provided under § 62.16300, each facility may have one and only one alternate designated representative, who may act on behalf of the designated representative. The agreement by which the alternate designated representative is selected must include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the facility and all affected EGUs at the facility and must act in accordance with the certification statement in § 62.16305(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 62.16305:
(i) The alternate designated representative must be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the facility and each affected EGU at the facility shall be bound by any decision or order issued to the alternate designated representative by the Administrator regarding the facility or any such affected EGU.
(c) Except in this section, § 62.16375, and §§ 62.16295 through 62.16315, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
(a) Except as provided under § 62.16315 concerning delegation of authority to make submissions, each submission under the CO
(b) The Administrator will accept or act on a submission made for a facility or an affected EGU only if the submission has been made, signed, and certified in accordance with paragraph (a) of this section and § 62.16315.
(a)
(b)
(c)
(2) Within 30 days after any change in the owners and operators of a facility or an affected EGU at the facility, including the addition or removal of an owner or operator, the designated representative or any alternate designated representative must submit a revision to the certificate of representation under § 62.16305 amending the list of owners and operators to reflect the change.
(d)
(1) If the change is the addition of an affected EGU that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the facility, then the certificate of representation must identify, in a format prescribed by the Administrator, the entity from whom the affected EGU was purchased or otherwise obtained (including name, address, telephone number, and facsimile transmission number (if any)), the date on which the affected EGU was purchased or otherwise obtained, and the date on which the affected EGU became located at the facility.
(2) If the change is the removal of an affected EGU, then the certificate of representation must identify, in a format prescribed by the Administrator, the entity to which the affected EGU was sold or that otherwise obtained the affected EGU (including name, address, telephone number, email address and facsimile transmission number (if any)), the date on which the affected EGU was sold or otherwise obtained, and the date on which the affected EGU became no longer located at the facility.
(a) A complete certificate of representation for a designated representative or an alternate designated representative must include the following elements in a format prescribed by the Administrator:
(1) Identification of the facility, and each affected EGU at the facility, for which the certificate of representation is submitted, including facility and affected EGU names, facility category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, unit identification number and type, identification number and nameplate capacity (in MWe, rounded to the nearest tenth) of each generator served by each such affected EGU, actual or projected date of commencement of commercial operation, net summer capacity at the affect EGU, and a statement of whether such facility is located in Indian country. If a projected date of commencement of commercial operation is provided, then the actual date of commencement of commercial operation must be provided when such information becomes available.
(2) The name, address, email address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the facility and of each affected EGU at the facility.
(4) The following certification statements by the designated representative and any alternate designated representative:
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility and each affected EGU at the facility”; and
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, an affected EGU, or where a utility or industrial customer purchases power from an affected EGU under a life-of-the-unit, firm power contractual arrangement, I certify that: I have given a written notice of my selection as the `designated representative' or `alternate designated representative', as applicable, and of the agreement by which I was selected to each owner and operator of the facility and of each affected EGU at the facility; and CO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(a) Once a complete certificate of representation under § 62.16305 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 62.16305 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of CO
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the elements in paragraphs (c)(1) through (4) of this section.
(1) The name, address, email address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative.
(2) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”).
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her.
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under § 62.16315(d) shall be deemed to be an electronic submission by me”; and
(ii) “Until this notice of delegation is superseded by another notice of delegation under § 62.16315(d), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under § 62.16315 is terminated.”
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(a)
(b)
(2) [Reserved]
(c)
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to CO
(B) The agreement by which the alternate authorized account representative is selected must include
(ii) A complete application for a general account must include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, email address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the CO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2)
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative; and
(C) Each person who has an ownership interest with respect to CO
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to CO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest.
(i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the CO
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the CO
(iii)(A) In the event a person having an ownership interest with respect to CO
(B) Within 30 days after any change in the persons having an ownership interest with respect to CO
(4) Objections concerning authorized account representative and alternate authorized account representative.
(i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the CO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of CO
(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, email address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under § 62.16320(c)(5)(iv) shall be deemed to be an electronic submission by me”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under § 62.16320(c)(5)(iv), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under § 62.16320(c)(5) is terminated.”
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(6)
(ii) If a general account has no CO
(d)
(e)
(a) By June 1, 2021, and by June 1 of each year prior to the beginning of each compliance period thereafter, the Administrator will record in each facility's compliance account the CO
(b) Except as specified in paragraph (a) of this section, the Administrator will record an allocation in the appropriate ATCS account by the date on which any allocation of CO
(c) When recording the allocation of CO
(d) By December 1, 2021 and December 1 of each year thereafter, the Administrator will record in each renewable energy project's general account, the CO
(e) By November 1 of the first year of each compliance period beginning in 2025, and each compliance period thereafter, the Administrator will record in each facility's compliance account the CO
(a) An authorized account representative seeking recordation of a CO
(b) A CO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each CO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each CO
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CO
(b) A CO
(c) Where a CO
(d) Within 5 business days of recordation of a CO
(e) Within 10 business days of receipt of a CO
(1) A decision not to record the transfer; and
(2) The reasons for such non-recordation.
(a)
(1) Were allocated for a year in such compliance period or a prior compliance period; and
(2) Are held in the facility's compliance account as of the allowance transfer deadline for such compliance period.
(b)
(1) Until the amount of CO
(2) If there are insufficient CO
(c)(1)
(2)
(i) Any CO
(ii) Any CO
(d)
(e)
(a) The owner or operator of an affected EGU must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter, unless such a plan is already in place under another program that requires CO
(1) For each operating hour, calculate the hourly CO
(2) Sum all of the hourly CO
(3) The owner or operator of an affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output (P
(4) The owner or operator of an affected EGU must measure and report the hourly CO
(i) The owner or operator of an affected EGU must install, certify, operate, maintain, and calibrate a CO
(ii) Calculate the hourly CO
(iii) Next, multiply each hourly CO
(iv) The hourly CO
(v) Sum all of the hourly CO
(vi) For each continuous monitoring system used to determine the CO
(5) The owner or operator of an affected EGU that exclusively combusts liquid fuel and/or gaseous fuel may, as an alternative to complying with paragraph (a)(4) of this section, determine the hourly CO
(i) Implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. The fuel flow meter(s) used to measure the hourly fuel flow rates must meet the applicable certification and quality-assurance requirements in sections 2.1.5 and 2.1.6 of appendix D (except for qualifying commercial billing meters). The fuel GCV must be determined in accordance with section 2.2 or 2.3 of appendix D, as applicable.
(ii) For each measured hourly heat input rate, use Equation G-4 in Appendix G to part 75 of this chapter to calculate the hourly CO
(iii) Determine the hourly CO
(iv) The hourly CO
(v) Sum all of the hourly CO
(vi) The owner or operator of an affected EGU may determine site-specific carbon-based F-factors (F
(6) The owner or operator of an affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output. The owner or operator must calculate net energy output according to paragraph (a)(6)(i) of this section.
(i) For each operating hour of a compliance period that was used in paragraph (a)(4) or (5) of this section to calculate the total CO
(A) Calculate P
(B) If applicable to your affected EGU (for example, for combined heat and power), you must calculate (Pt)
(ii) [Reserved]
(7) In accordance with § 60.13(g), if two or more affected EGUs implementing the continuous emissions monitoring provisions in paragraph (a)(1) of this section share a common exhaust gas stack and are subject to the same emissions standard, then the owner or operator may monitor the hourly CO
(8) In accordance with § 60.13(g), if the exhaust gases from an affected EGU implementing the continuous emissions monitoring provisions in paragraph (a)(3) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), the hourly CO
(b) [Reserved]
(a) A CO
(b) Any CO
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any ATCS account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
(a) You must prepare and submit reports according to paragraphs (a) through (e) of this section, as applicable.
(1) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter and you must include the following information, as applicable in the quarterly reports:
(i) The hourly CO
(ii) The calculated CO
(iii) The sum of the CO
(iv) The net electric output and the net energy output (P
(v) The sum of the hourly net energy output values for all of the unit or stack operating hours in the compliance period; and
(vi) If the report covers the final quarter of a compliance period, then you must include the CO
(2) [Reserved]
(b) The designated representative of each affected EGU at the facility must make all submissions required under the CO
(c) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA.
(d) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart.
(e) If your affected EGU captures CO
(1) Report in accordance with the requirements of 40 CFR part 98, subpart RR, of this chapter, if injection occurs on-site; or
(2) Transfer the captured CO
(f) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected EGUs.
(a) The owner or operator of each affected EGU must maintain the records, as described in paragraphs (a)(1) and (2) of this section, for at least 5 years following the date of each compliance period, occurrence, measurement, maintenance, corrective action, report, or record.
(1) The owner or operator of an affected EGU must maintain each record on site for at least 2 years after the date of each compliance period, compliance true-up period, occurrence, measurement, maintenance, corrective action, report, or record, whichever is latest, according to § 60.7 of this chapter. The owner or operator of an affected EGU may maintain the records off site and electronically for the remaining year(s).
(2) The owner or operator of an affected EGU must keep all of the following records:
(i) All emissions monitoring information, in accordance with this subpart;
(ii) Copies of all reports, compliance certifications, documents, data files, calculations and methods, other submissions and all records made or required under, or to demonstrate compliance with an affected EGU's emission standard under § 62.16220 and any other requirements of, the CO
(iii) Data that is required to be recorded by 40 CFR part 75, subpart F, of this chapter; and
(iv) Data with respect to any allowances used by the affected EGU in its compliance demonstration including the information in paragraphs (a)(2)(iv)(A) and (B) of this section.
(A) All documents related to any set-aside allowances used in a compliance demonstration, including each eligibility application, EM&V plan, M&V report, and independent verifier verification report associated with the issuance of each specific set-aside allowance, and each regulatory approval and any documentation that supports the issuance of each set-aside allowance by the Administrator.
(B) All records and reports relating to the surrender and retirement of allowances for compliance with this regulation, including the date each individual allowance with a unique serial identification number was surrendered and/or retired.
(b) [Reserved]
(a) The Administrator may review and conduct independent audits concerning
(b) The Administrator may deduct CO
The terms used in this subpart have the meanings set forth in this section as follows:
(1) An affected EGU;
(2) A renewable energy set-aside;
(3) An output-based set-aside; or
(4) Any other entity specified by the Administrator.
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function or any other person who performs similar policy- or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or state, federal, or other public agency, a principal executive officer or ranking elected official.
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, CO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, CO
(1) Compliance Period 1 means the period of 3 calendar years from January 1, 2022 to December 31, 2024.
(2) Compliance Period 2 means the period of 3 calendar years from January 1, 2025 to December 31, 2027.
(3) Compliance Period 3 means the period of 2 calendar years from January 1, 2028 to December 31, 2029.
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow;
(2) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(3) A CO
(4) An O
(1) In accordance with this subpart; and
(2) With regard to a period before the affected EGU or facility is required to measure, record, and report such air pollutants in accordance with this subpart, and in accordance with part 75 of this chapter.
(1) The net electric or mechanical output from the affected facility, plus 100 percent of the useful thermal output measured relative to SATP conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the affected EGU (
(2) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output (
(1) Any holder of any portion of the legal or equitable title in an affected EGU at the facility or the affected EGU;
(2) Any holder of a leasehold interest in an affected EGU at the facility or the affected EGU, provided that, unless expressly provided for in a leasehold agreement, “owner” does not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly) on the revenues or income from such affected EGU; and
(3) Any purchaser of power from an affected EGU at the facility or the affected EGU under a life-of-the-unit, firm power contractual arrangement.
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
The measurements, abbreviations, and acronyms used in this subpart are defined as follows:
(a) This subpart sets forth the requirements for the Clean Power Plan (CPP) CO
(b) The pollutants regulated by this subpart are greenhouse gases. The greenhouse gas limitations in this subpart are in the form of an emission standard for carbon dioxide (CO
(c)
(2) For the purposes of § 52.21(b)(50)(ii) of this chapter, with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter.
(3) For the purposes of § 70.2 of this chapter, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in § 70.2 of this chapter.
(4) For the purposes of § 71.2 of this chapter, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in § 71.2 of this chapter.
(a) You are subject to this subpart if you are the owner or operator of an affected electric generating unit (EGU) located within a State that has incorporated by reference this subpart as a State plan, or portion of a State plan, that has been approved by the Administrator and is effective under subpart UUUU of part 60 of this chapter, or if this subpart is promulgated and effective as a federal plan in your State under part 62 of this chapter.
(b) An affected EGU is any steam generating unit, IGCC, or stationary combustion turbine that meets the applicability requirements in §§ 60.5840(b) and 60.5845 of this chapter.
(a)
(2) The exemption under paragraph (a)(1) of this section will become effective on the first day of the compliance period immediately following the compliance period in which the retirement took effect. Within 30 days of the affected EGU's permanent retirement, the designated representative must submit a statement to the Administrator. The statement must state, in a format prescribed by the Administrator, that the affected EGU was permanently retired on a specified date and will comply with the requirements of paragraph (b) of this section.
(b)
(2) For a period of 5 years from the date the records are created, the owners and operators of an affected EGU exempt under paragraph (a) of this section must retain, at the affected EGU, records demonstrating that the affected EGU is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the affected EGU is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of an affected EGU exempt under paragraph (a) of this section must comply with the requirements of the CO
(a)
(b)
(2) The emissions data determined in accordance with § 62.16540 must be used to determine compliance with the CO
(c)
(2) An ERC qualifies for the compliance demonstration specified in paragraph (c)(1) of this section if it:
(i) Has a unique serial number;
(ii) Represents one whole MWh of actual energy generated or saved with zero associated carbon dioxide emissions;
(iii) Was issued to an eligible resource that meets the requirements of § 62.16435 or to an affected EGU that meets the requirements of § 62.16434, by the Administrator through an ERC tracking system or the ATCS; and
(iv) Was surrendered and retired only once for purposes of compliance with this regulation by the Administrator through an ERC tracking system or the ATCS.
(3) An ERC does not qualify for the compliance demonstration specified in paragraph (c)(1) of this section if it does not meet the requirements of paragraph (c)(2) of this section or if any State has used that same ERC for purposes of demonstrating achievement of its state measures.
(4) As of the ERC transfer deadline for a compliance period, the owners and operators of each affected EGU must hold, in the affected EGU's compliance account, sufficient ERCs to demonstrate compliance with its applicable emission standard listed in Table 1 of this subpart pursuant to the requirement of paragraph (c)(1) of this section.
(5) If an affected EGU exceeds its emission standard during a compliance period, then:
(i) The owners and operators of the affected EGU must hold ERCs required for deduction under § 62.16535(e);
(ii) The owners and operators of the affected EGU are subject to federal enforcement pursuant to sections 113(a)-(h), and section 304, of the Clean Air Act, and the United States, States, and other persons have the ability to enforce against violations (including if an affected EGU does not meet its emission standard based on its emissions, or use of ERCs that meet the compliance demonstration in § 62.16420 (c)(2)) and secure appropriate corrective actions, and the owners and operators must pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act, and each day of such compliance period will constitute a separate violation of this subpart and the Clean Air Act;
(iii) If an affected EGU does not meet its emission standard because it did not meet the emissions standard based on its stack emissions and generation alone and it did not obtain sufficient qualifying ERCs to meet its emission standard by July 1 of the year following the relevant compliance period, then it may be subject to federal enforcement pursuant to Sections 113(a)-(h), 42 U.S.C. 7413(a)-(h), and Section 304 of the Clean Air Act, 42 U.S.C. 7604, and the United States, states, and other persons have the ability to enforce violations and secure corrective actions; and
(iv) If an affected EGU obtained sufficient facially valid ERCs to meet its emission standard, but those ERCs were found to be invalid, then it may be subject to federal enforcement as specified in paragraph (c)(5)(iii) of this section.
(d)
(1)
(2)
(3)
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(4)
(e)
(2) The applicable requirements of this subpart, as well as other terms or conditions necessary to ensure compliance with the applicable requirements, may be added to, or changed in, a title V permit using minor permit modification procedures in accordance with §§ 70.7(e)(2) and 71.7(e)(1) of this chapter, provided that such changes do not conflict with any existing terms of the permit. This paragraph explicitly provides that the addition of, or change to, an affected EGU's description as described in the prior sentence is eligible for minor permit modification procedures in accordance with §§ 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.
(3) No title V permit revision will be required for any crediting, holding, deduction, or transfer of ERCs in accordance with this subpart, provided that the requirements applicable to such creditings, holdings, deductions, or transfers of ERCs are already incorporated in such permit.
(f)
(g)
(a) Unless otherwise stated, any time period scheduled, under the CO
(b) Unless otherwise stated, any time period scheduled, under the CO
(c) Unless otherwise stated, if the final day of any time period, under the CO
The administrative appeal procedures for decisions of the Administrator under the CO
(a)(1) The Administrator will participate in the Clean Energy Incentive Program, established under subpart UUUU of part 60 of this chapter, on behalf of any state for whom this subpart is promulgated as a federal plan under section 111(d) of the Act. The Administrator will award, on behalf of each such state, early action ERCs for generation and savings achieved in 2020 and/or 2021 that result from the
(i) Metered wind power;
(ii) Metered solar power; and
(iii) Demand-side EE implemented in a low-income community.
(2) Eligible RE projects must commence construction, and eligible demand-side EE projects must commence implementation, after September 6, 2018 for those states on whose behalf the EPA is implementing the federal plan. Eligible projects must be located in or benefit the state on whose behalf the EPA is implementing the federal plan.
(b) Early action ERCs will be distributed pursuant to a process to be prescribed by the Administrator, and in a manner to be demonstrated by the Administrator to have no impact on the aggregate emission performance of affected EGUs required to meet rate-based emission standards during the compliance periods.
(c) The Administrator will match these early action ERCs with additional matching ERCs pursuant to a process to be prescribed by the Administrator. Matching awards will be made up to a limit equivalent to the state's pro rata share of 300 million short tons of CO
(d) The awards, including the matching award, will be executed as follows:
(1) For RE projects that generate metered MWh from wind or solar resources: For every two MWh generated, the project will receive one early action ERC under paragraph (b) of this section and one matching ERC from the match under paragraph (c) of this section; and
(2) For EE projects that benefit low-income communities as determined by the Administrator solely for purposes of this subpart: For every two MWh in end-use demand savings achieved, the project will receive two early action ERCs under paragraph (b) of this section and two matching ERCs from the match under paragraph (c) of this section.
(a) ERCs may only be issued to affected EGUs under the conditions listed in paragraphs (b) and (c) of this section.
(b) For affected EGUs that emit below their applicable emission standard, the amount of ERCs generated must be calculated using the following equation:
(c) Stationary combustion turbines that meet the definition of an affected EGU may generate net energy output MWh gas shift ERCs (GS-ERCs) for all hours of operation during a given compliance period according to paragraphs (c)(1) through (3) of this section.
(1) To calculate the number of GS-ERCs:
GS-ERCs = EGU Generation * Incremental Generation Factor * GS-ERC Emission Factor
(2) To calculate the GS-ERC Emission factor for your specific affected EGU you must use the following equation:
(3) Notwithstanding any other provision of this subpart, GS-ERCs must not be used for compliance by an affected EGU that is a stationary combustion turbine. Stationary combustion turbines may use other ERCs in their compliance demonstration.
(a) ERCs may only be issued to an eligible resource that meet each of the requirements in paragraphs (a)(1) through (4) of this section. All categories of resources other than on-shore utility scale wind, utility scale solar photovoltaics, concentrated solar power, geothermal power, nuclear energy, or utility scale hydropower, and all provisions of this subpart relating to such resources, are not available or applicable in States where this subpart has been promulgated as a federal plan pursuant to section 111(d)(2) of the Act.
(1) Resources qualifying for eligibility only include resources which increased new installed electrical generation nameplate capacity, or new electrical savings measures installed or implemented after January 1, 2013. If a resource had a nameplate capacity uprate, then ERCs may be issued only for the difference in generation between the uprated nameplate capacity and its nameplate capacity prior to the uprate. ERCs must not be issued for generation for an uprate that followed a derate that occurred on or after January 1, 2013. A resource that is relicensed or receives a license extension is considered existing
(2) The resource must be connected to, and delivers energy to or saves electricity, on the electric grid in the contiguous United States.
(3) The resource is located in a State whose affected EGUs are subject to rate-based emission standards pursuant to this regulation, unless the resource is located in a State with mass-based emission standards and the resource can demonstrate (
(4) The resource falls into one of the following categories of resources:
(i) Renewable electric generating technologies using one of the following renewable energy resources: wind, solar, geothermal, hydro, wave, tidal;
(ii) Qualified biomass;
(iii) Waste-to-energy (biogenic portion);
(iv) Nuclear energy;
(v) A non-affected combined heat and power unit, including waste heat power; or
(vi) A demand-side EE or demand-side management measure that saves electricity and is calculated on the basis of quantified ex poste savings, not “projected” or “claimed” savings.
(b) Any resource that does not meet the requirements of this subpart cannot generate ERCs for use in the compliance demonstration required under § 62.16420.
(c) ERCs may not be issued to any of the following:
(1) New, modified, or reconstructed EGUs that are subject to subpart TTTT of part 60 of this chapter, except CHP units that meet the requirements of a CHP unit under paragraph (a) of this section;
(2) EGUs that do not meet the applicability requirements of § 62.16410, except CHP units that meet the requirements of a CHP unit under paragraph (a) of this section;
(3) Measures that reduce CO
(4) Any measure not approved by the EPA to generate ERCs in connection with a specific State plan.
(a) If an eligible resource is found to not meet the requirements of § 62.16435 in the Rate-based Trading Program, then the Administrator will revoke the eligibility of the eligible resource to be issued ERCs. In addition, the provisions of § 62.16450(d) may apply.
(b) Any instance of intentional misrepresentation in an eligibility application or monitoring and verification (M&V) report may be cause for revocation of the qualification status of an eligible resource.
(c) Repeated instances of error or misstatement of MWh of electricity generation or savings in submitted M&V reports, or in any other submissions may be cause for the Administrator to revoke the eligibility of an eligible resource to be issued ERCs.
(d) In the event of an intentional misrepresentation, or repeated instances of error or misstatement, in program submissions, by the authorized account representative of the eligible resource, the Administrator may prohibit the eligible resource from any further eligibility to be issued ERCs. In addition, the provisions of § 62.16450 (a) through (d) may apply.
The process and requirements for issuance of ERCs for affected EGUs and eligible resources are set forth in paragraphs (a) through (f) of this section.
(a)
(1) Identification of the authorized account representative of the eligible resource, including the authorized account representative's name, address, email address, telephone number, and ERC tracking system account number.
(2) Identification of the eligible resource(s), including the information in paragraphs (a)(2)(i) through (v) of this section.
(i) For an eligible resource, the physical location of the eligible resource; contact information for the owner or operator of the eligible resource, if different from the designated representative or authorized account representative; eligible resource generator prime mover and/or technology type; eligible resource nameplate capacity; eligible resource category (
(A) For an eligible resource with a nameplate capacity of1 MW or more, a copy of the most recent filing of a copy of the generating facility's U.S. Energy Information Agency's Annual Electric Generator Report Form EIA-860.
(B) For an electric generating resource with a nameplate capacity of less than 1 MW, the information that would be contained in U.S. Energy Information Agency's Annual Electric Generator Report Form EIA-860, if that electric generating facility had nameplate capacity of 1 MW or more.
(ii) For an energy-saving resource that is project-based, a detailed description of the demand-side EE or electricity savings project, including: Location and specifications of the building(s), facility(ies), or installations where energy-saving measures were implemented or will be implemented; owner and operator of the building(s), facility(ies), or installations where the energy-saving measures are implemented or will be implemented; the parties implementing the energy-saving project, including lead contractor(s), subcontractors, and consulting firms (if different from the authorized account representative); energy-saving measures installed and/or energy-savings practices implemented (or to be installed/implemented); specifications of equipment and materials installed, or to be installed, as part of the energy-saving project; project plans and technical schematics, as applicable.
(iii) For an energy-savings resource that involves an EE requirement or program, a description of the electricity savings program, including: Overall approach or “logic” to the requirement or program, including applicable strategies and activities, along with key assumptions regarding how such strategies and activities will achieve quantifiable reductions in electricity consumption; location and geographic
(iv) For other electricity-saving resources (
(v) For eligible resources with distributed locations, such as measures at multiple residential, commercial, or industrial buildings, at a minimum, aggregated information about the location of measures that constitute an eligible resource, provided that the accredited independent verifier and the Administrator have the ability to access information specifying the location of each discrete measure that constitutes an eligible resource.
(3) Demonstration that the eligible resource meets all applicable eligibility requirements in § 62.1435.
(4) A certification that the eligibility application has only been submitted to the Administrator or pursuant to an EPA-approved multi-state approach where States are providing for joint issuance of ERCs pursuant to the authority in their individual State plans.
(5) An evaluation measurement and verification (EM&V) plan.
(6) A verification report from an accredited independent verifier who meets the requirements of §§ 62.16470 and 62.16475.
(7) An authorization that provides for the following: The Administrator may inspect (including a physical inspection of the eligible resource and its meter) and/or audit the eligible resource at any time and verify that the eligible resource and the EM&V plan have been implemented as described in the eligibility application.
(8) The following statement, signed by the designated representative of the eligible resource:
(i) “I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my personal knowledge and/or inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(ii) [Reserved]
(9) Any other information required by the Administrator.
(b)
(c)
(d)
(e)
(f)
(a) In the event of error or misstatement of quantified MWh of electricity generation or savings in a previous M&V report for which ERCs have been issued, the Administrator may adjust the number of ERCs issued in a subsequent reporting period to address the error or misstatement, by subtracting a number of MWh from the quantified and verified MWh in the M&V report for the subsequent reporting period. In the event that an error or inadvertent misstatement occurs in a final M&V report for an eligible resource, for which ERCs have been issued, the provisions of paragraph (b) of this section will apply.
(b) In the event of error or misstatement of quantified MWh of electricity generation or savings in the final M&V report for an eligible resource, for which ERCs have been issued, the Administrator will revoke ERCs from the general account held by the authorized account representative of the eligible resource, in an amount necessary to correct the error or misstatement. In the event that the general account of the eligible resource holds an insufficient number of ERCs to correct the error or misstatement, the authorized account representative must submit to the Administrator within 30 days a number of ERCs necessary to correct the error or misstatement. Failure to meet this requirement will
(c) The Administrator may freeze the general account held by an authorized account representative of an eligible resource at any time, for cause, if the Administrator determines ERCs have been improperly issued, based on a misrepresentation or misstatement in an eligibility application or M&V report. The Administrator may also freeze the general account of an authorized account representative of an eligible resource pending investigation of potential misrepresentation, error, or misstatement in an eligibility application of an eligible resource, or in an M&V report for which ERCs have been issued. Freezing a general account will prevent transfer of ERCs out of the account.
(d) If ERCs are issued for an eligible resource that is found to be ineligible, then the Administrator may take the actions in paragraphs (d)(1) through (3) of this section.
(1) Freeze the general account for the eligible resource, preventing any transfers of ERCs out of the account.
(2) Revoke and deduct ERCs held in the general account of the authorized account representative for an eligible resource, in a number equal to the number of ERCs issued for the ineligible eligible resource.
(3) In the event that the general account of the eligible resource holds a number of ERCs less than the number of ERCs issued for the ineligible eligible resource, the delegated representative of an eligible resource must submit to the Administrator within 30 days a number of ERCs necessary to fully account for all ERCs issued for the ineligible eligible resource. Failure to meet this requirement will result in prohibition of the eligible resource from further participation in the program, unless reauthorized at the discretion of the Administrator.
(e) The Administrator may temporarily or permanently suspend issuance of ERCs for an eligible resource, for the following reasons in paragraphs (e)(1) through (3) of this section.
(1) Pending investigation of potential misrepresentation, error, or misstatement in an M&V report, for which ERCs have been issued, or the eligibility status of an eligible resource.
(2) In the case of repeated error or misstatements in submitted M&V reports.
(3) In the case of an intentional misrepresentation in a submitted M&V report.
(a)
(b)
(c)
(1) For a nuclear energy resource or a renewable energy resource with a nameplate capacity of 10 kW or more and for a renewable energy resource with a nameplate capacity of less than 10 kW for which metered data are available, each EM&V plan must specify that the requirements in paragraphs (c)(1)(i) through (vi) of this section are met.
(i) The generation data are physically measured on a continuous basis using a revenue-quality meter, which means a meter used by a control area operator for financial settlements, or a meter that meets the American National Standards Institute No. C12.20., Code for Electricity Metering, metering accuracy standards, or a meter that meets an alternative equivalent standard that has been approved in advance of its use to measure generation pursuant to this regulation by the EPA.
(ii) The generating data are measured at the generator's bus bar, or, for a renewable energy resource with a nameplate capacity of less than 10 kW that is interconnected behind an individual business or household meter, the generating data were measured at the AC output of the inverter and adjusted to reflect the only energy delivered into either the transmission or distribution grid at the generator bus bar and not any energy used on-site at the generator.
(iii) The generation data from only one eligible resource generating unit may be associated with each meter, and generation data may not be aggregated, unless all the following provisions are met:
(A) All of the generating units have the same essential generation characteristics;
(B) All of the generating units are located in the same State;
(C) The nameplate capacity of the individual units being aggregated is each less than 150 kW, and units collectively do not exceed a total nameplate capacity of 1 MW when aggregated, or alternative requirements approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan or M&V report is submitted; and
(D) The generation data are measured by the same type of meter that is subject to the same maintenance and quality assurance procedures.
(iv) The generation data are collected electronically and telemetered from the generator to its control area operator and verified through a control area energy accounting or settlement process which occurs at least monthly, unless the generation unit does not go through a control area operator, in which case the generation data must be collected by manual meter readings conducted by an independent verifier that is either not affiliated with the owner or operator of the qualifying renewable energy generating resource or is precluded pursuant to the relevant State plan from the ability to transfer or retire ERCs issued to that qualifying renewable energy generating resource or, if the generating unit is less than 10 kw and does not generate enough electricity to enable monthly reporting, then the data may be self-reported and reported no less than annually.
(v) The generation data serve a load that otherwise would have been served by the grid if not for the generator. Specifically:
(A) ERCs shall not be issued for energy generation used to supply the ancillary equipment used to operate a generating station or substation (“station service”) or parasitic load on the generator's side of the point of interconnection; and
(B) For generators interconnected to transmission systems and with on-site loads other than station service drawing generation before the metering point, ERCs may be issued for on-site load, if the owner or operator of the eligible resource can demonstrate that the metering used is capable of distinguishing between on-site load and station service.
(vi) Any other requirements approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan is submitted.
(2) For a renewable energy resource with a nameplate capacity of less than 10 kW and that does not have a meter, each EM&V plan must require that the following requirements in paragraphs (c)(2)(i) though (vii) of this section are met.
(i) Metered data are unavailable.
(ii) At least 1 MW of net energy output is generated to the distribution or transmission system over a continuous 365-day period.
(iii) The generation data may not be aggregated, unless the following provisions are met:
(A) All of the generating units have the same essential generation characteristics;
(B) All of the generating units are located in the same State;
(C) The nameplate capacity of the individual units being aggregated is each less than 150 kW, and units collectively do not exceed a total nameplate capacity of 1 MW when aggregated, or alternative requirements approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan or M&V report is submitted; and
(D) The generation data are measured by the same generation estimating software or algorithms.
(iv) The generation data are measured on at least a monthly basis using generation estimating software or algorithms that are based on an on-site inspection prior to interconnection and a resource study (wind, shading, solar irradiance, depending on the resource), or engineering information that takes into account the capacity, age, and type of qualifying energy generating resource, and all input parameters and assumptions must be clearly delineated, or if the generating unit does not generate enough electricity to enable monthly reporting, then the data may be reported no less than annually.
(v) The generation data are self-reported to the distribution utility through an electronic internet-based portal with software that reports total and hourly generation.
(vi) The generation data serve a load that otherwise would have been served by the grid if not for the generator. The ERC is only based on generation transferred from the eligible resource to the transmission or distribution grid, and is not based on the generation used on-site by the customer.
(vii) Any other requirements approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan is submitted.
(3) For qualified biomass feedstocks used, in addition to the requirements of paragraphs (c)(1) or (2) of this section, whichever section is applicable, each EM&V plan must demonstrate that the requirements approved by the EPA for that biomass feedstock, and its associated biogenic CO
(4) For a waste-to-energy resource, in addition to the requirements of paragraphs (c)(1) or (2) of this section, as applicable, and paragraph (c)(3) of this section, each EM&V plan must specify:
(i) The total net energy generation from the resource in MWh;
(ii) The method for determining the specific portion of the total net energy output from the resource that is related to the biogenic portion of the waste materials; and
(iii) The net energy output measured with the relevant method approved by the EPA in connection with the specific State plan pursuant to which that EM&V plan is submitted demonstrates that the requirements approved by the EPA in connection with that State plan have been met.
(5) For a combined heat and power unit, in addition to the requirements of paragraphs (c)(1) or (2) of this section, as applicable, and paragraph (c)(3) of this section, each EM&V plan must meet one of the requirements in paragraphs (c)(5)(i) through (iv) of this section, as applicable, and any other requirements approved by the EPA.
(i) If the combined heat and power unit has an electric generating capacity greater than 25 MW, then the EM&V plan must meet the requirements that apply to an affected EGU under § 62.16540.
(ii) If the combined heat and power unit has an electric generating capacity less than or equal to 25 MW and greater than 1 MW, and it uses only natural gas and/or distillate fuel oil, then the EM&V plan must meet the low mass emission unit CO
(iii) If the combined heat and power unit has an electric generating capacity less than or equal to 25 MW and greater than 1 MW, and it uses anything other than only natural gas and/or distillate fuel oil, then the EM&V plan must meet the low mass emission unit CO
(iv) If the combined heat and power unit has an electric generating capacity less than or equal to 1 MW the unit must keep monthly cumulative recordings of useful thermal output and fossil fuel input along with the determination of baseline thermal source efficiencies based on manufacturer data. For CHP units that directly serve on-site end-use electricity loads, avoided T&D system losses can be assessed as is commonly practiced with demand-side EE.
(6) For demand-side electricity savings that avoid a transmission and distribution loss, each EM&V plan must measure the transmission and distribution loss based on the lesser of 6 percent of the facility- or premises-level electricity savings measured at the electricity customer's meter, or the statewide annual average transmission and distribution loss rate (expressed as a percentage) from the most recent year that is published in the US EIA State Electricity Profile. No other transmission and distribution loss factors may be used in calculating the electricity savings.
(7) Each EM&V plan for an EE program, EE project, or EE measure must specify how each of the requirements in paragraphs (c)(7)(i) through (x) of this section will be met in quantifying the electricity savings from that EE program, EE project, or EE measure.
(i) All electricity savings must be quantified on an ex-post basis, which means after the electricity savings have occurred, or on a real-time basis, which means at the time the electricity savings are occurring. Electricity savings must not be quantified on an ex-ante basis, which means estimates of MWh savings that are generated prior to implementing the subject EE program, EE project, or EE measure, and that are not quantified using EM&V methods and procedures.
(ii) All electricity savings must be quantified and verified based on methods and procedures detailed in an industry best-practice EM&V protocol or guideline. Each EM&V plan must include a demonstration of how the best-practice protocol or guideline was selected and will be applied to the specific EE program, EE project, or EE measure covered in the EM&V plan, and an explanation of why that particular protocol or guideline was selected. Protocols and guidelines are considered to be best practice if they:
(A) Have gone through a rigorous and credible peer review process that shows the applicable methods to be valid through empirical testing; and
(B) Have been accepted and approved for use by identifiable state regulatory commissions. Examples of such protocols and guidelines that may be provided in EM&V guidance issued by the Administrator will be acceptable.
(iii) All electricity savings must be quantified as the difference between the observed electricity use and a common practice baseline (CPB), which is the equipment that would typically have been installed—or that a typical
(A) Characteristics of the EE program, EE project, or EE measure;
(B) The delivery mechanism used to implement the EE program, EE project, or EE measure (
(C) Local consumer and market characteristics;
(D) Applicable building energy codes and standards and average compliance rates; and
(E) The method applied: Project-based measurement and verification (PB-MV), comparison group approaches, or deemed savings.
(iv) All electricity savings must be quantified by applying one or more of the following methods: Project-based measurement and verification (PB-MV), comparison group approaches, or deemed savings.
(A) If a comparison group approach is used, then the EM&V plan must quantify electricity savings by taking the difference between a comparison group's electricity use and the electricity use of EE program participants. Comparison group approaches may include randomized control trials and quasi-experimental methods, as described in industry best-practice protocols and guidelines. Examples of such protocols and guidelines provided in EM&V guidance that may be issued by the Administrator will be acceptable.
(B) If deemed savings are used, then the EM&V plan must specify that the deemed savings values will only be used for the specific EE measure for which they were derived. The EM&V plan must also specify the name and Web address of the technical reference manual (TRM) in which all deemed electricity savings values will be documented. Prior to use in an EM&V plan, all TRMs must undergo a review process in which the public, stakeholders, and experts are invited—with adequate advance notification (via the internet and other social media)—to provide comment, have at least 2 months to provide comment, and in which all such comments and associated responses are made publicly available. All TRMs must also be publicly accessible over the full period of time in which they are being used in conjunction with an EM&V plan for the purpose of quantifying savings, and must be subsequently updated in the same manner at least every 3 years. The TRM must indicate, for each subject EE measure, the associated electricity savings value, the conditions under which the value can be applied (including the climate zone, building type, manner of implementation, applicable end uses, operating conditions, and effective useful life), and the manner in which the electricity savings value was quantified, which must include applicable engineering algorithms, source documentation, specific assumptions, and other relevant data to support the quantification of savings from the subject EE measure.
(v) All EE programs, EE projects, or EE measures must be quantified at time intervals (in years) sufficient to ensure that MWh savings are accurately and reliably quantified. Such time intervals must be specified and explained in the EM&V plan. Factors that must be taken into consideration when determining the appropriate time interval include the characteristics of the specific EE program, EE project, or EE measure, expected variability in electricity savings (where greater variability necessitates more frequent quantification), the expected scale and magnitude of the electricity savings (where greater quantities of savings necessitate more frequent quantification), and the experience implementing and quantifying savings from the resource (where less experience—for example, with new and innovative EE program types—necessitates more frequent quantification). The time intervals must end no sooner than the last day of the effective useful life of the EE program, EE project, or EE measure, and must last no longer than:
(A) Every 4-year intervals for building energy codes and product standards;
(B) Every 1, 2, or 3 years for public or consumer-funded EE program, EE project, or EE measure, as relevant for the type of EE program, EE project, or EE measure and factors listed in paragraph (c)(7)(v) of this section; and
(C) Annually for commercial and industrial projects, unless the resource provider can provide a reasonable justification in the EM&V plan for why an annual time interval is not feasible, and can additionally explain how the accuracy and reliability of savings values will not be lessened.
(vi) EM&V plans must specify and document how the EM&V components in paragraphs (c)(7)(vi)(A) through (E) of this section will be analyzed, considered, or otherwise addressed in the quantification and verification of electricity savings.
(A) The effects of changes in independent factors on reported electricity savings (
(B) The effective useful life (EUL) or duration of time the EE measure is anticipated to remain in place and operable with the potential to save electricity, which must be based on the application of EM&V methods, an industry best-practice persistence study, deemed estimates of effective useful life, or a combination of all three.
(C) The potential sources of double counting, and the associated steps for avoiding and correcting for it, such as:
(D) The EE savings verification approaches for ensuring that EE measures have been properly installed, are operating as intended, and therefore have the potential to save electricity,
(E) The interactive effects of EE programs, EE projects, or EE measures on electricity usage, which are increases or decreases in electricity usage at an end-use facility or premises that occurs outside of specific end-uses(s) targeted by the EE program, EE project, or EE measure (
(vii) The EM&V plan must specify how the accuracy and reliability of the electricity savings of the EE program, EE project, or EE measure will be assessed, and must discuss the rigor of the method selected to quantify the electricity savings. It must also discuss the approaches that will be used to control all relevant types of bias and to minimize the potential for systematic and random error, as well as the program- or project-specific circumstances in which such bias and error are likely to arise. Approaches to minimizing bias and error are provided in the EM&V guidance that may be issued by the Administrator will be acceptable.
(viii) If sampling will be used to quantify the electricity savings from an EE program, then the MWh estimates derived from sampling must have at least 90 percent confidence intervals whose end points are no more than ±10 percent of the estimate, and the statistical precision of the associated estimates must be specified in the EM&V plan.
(ix) All data sources and key assumptions used to quantify electricity savings must be described in the EM&V plan.
(x) Any additional information necessary to demonstrate that the electricity savings were appropriately quantified and verified. Approaches to quantifying and verifying savings from several EE program and EE project types that are provided in EM&V guidance that may be issued by the Administrator will be acceptable.
(d) You must ensure that any EM&V plan submitted pursuant to this subpart includes the following certification:
(1) “I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) [Reserved]
(a)
(b)
(1) For the first M&V report submitted, documentation that the electricity-generating resources, electricity-saving measures, or practices were installed or implemented consistent with the description in the approved eligibility application required in § 62.16445(a); and
(2) For each M&V report submitted:
(i) Identification of the time period covered by the M&V report;
(ii) A description of how relevant quantification methods, protocols, guidelines, and guidance specified in the EM&V plan were applied during the reporting period to generate the quantified MWh of generation or MWh of electricity savings;
(iii) Documentation (including data) of the energy generation and/or electricity savings from any activity, project, measure, resource, or program addressed in the EM&V report, quantified and verified in MWh for the period covered by the M&V report, in accordance with its EM&V plan, and based on ex-post energy generation or savings;
(iv) Documentation of any change in the energy generation or savings capability of the eligible resource during the period covered by the M&V report and the date on which the change occurred, and either certification that the eligible resource continued to meet all eligibility requirements during the reporting period covered by the M&V report or disclosure of any material changes to the eligible resource from the description of the eligible resource in the approved eligibility application, which must include any change in the energy generation (
(v) Documentation of any change in ownership interest of the qualifying eligible resource (including the date of the change).
(c) You must ensure that any M&V report submitted pursuant to this subpart includes the following certification:
(1) “I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) [Reserved]
(a) A verification report included as part of an eligibility application or an M&V report must meet the requirements of paragraph (b) of this section (for the eligibility application verification report) and paragraph (c) of this section (for the M&V report verification report) and include the following:
(1) A verification statement that sets forth the findings of the accredited independent verifier, based on the verifier's assessment of the information and data in the eligibility application or M&V report that is the subject of the verification report, including an assessment of whether the eligibility application or M&V report contains any material misstatements or material data discrepancies, and whether the submittal conforms with applicable regulatory requirements. The verification statement must clearly identify how levels of assurance and materiality are defined as part of the verifier assessment.
(2) The following statement, signed by the accredited independent verifier: “I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my personal knowledge and/or inquiry of those individuals with primary responsibility
(b) A verification report included as part of an eligibility application must, at a minimum, describe the review conducted by the accredited independent verifier and verify each of the following:
(1) The eligibility of the eligible resource to be issued ERCs pursuant to this regulation, in accordance with § 62.16435 and § 62.16445(a), including an analysis of the adequacy and validity of the information submitted by the authorized account representative to demonstrate that the eligible resource meets each applicable requirement of § 62.16435 and § 62.16445(a).
(2) The eligible resource is not duplicative of a resource used to meet emission standards or a state measure in another approved State plan.
(3) The eligible resource exists or the practice or activity will be implemented in the manner specified in the eligibility application.
(4) The EM&V plan meets the requirements of § 62.16455.
(5) Disclosure of any mandatory or voluntary programs to which data is reported relating to the eligible resource (
(6) Any other information required by the Administrator or that the accredited independent verifier finds, in its professional opinion, is necessary to assess the adequacy and validity of information and data supplied by the authorized account representative.
(c) A verification report included as part of a M&V report must, at a minimum, describe the review conducted by the accredited independent verifier and verify the following:
(1) The adequacy and validity of the information and data submitted in the submittal by the authorized account representative to quantify eligible MWh of electric generation or electricity savings during the period for which the authorized account representative seeks issuance of ERCs, as well as all supporting information and data identified in the EM&V plan and M&V report. This analysis must include a quality assurance and quality control check of the data and ensure that all generation or savings data are within a technically feasible range for that specific eligible resource.
(i) For metered generation, the data validity check must compare reported electricity generation to an engineering estimate of the maximum generation potential of the qualified renewable energy resource, based on, at a minimum, its maximum nameplate capacity in MW and the number of days since the prior cumulative meter reading was entered in the ERC tracking system. If the data entered exceed the estimated technically feasible generation, then the reported data and the estimate must be analyzed in the verification report.
(ii) For all electricity generated or saved, the accredited independent verifier must describe the likely source of any data discrepancy and determine in the verification report any MWh generated or saved.
(2) The M&V report meets the requirements of § 62.16460.
(3) Any other information required by the Administrator or that the accredited independent verifier finds, in its professional opinion, is necessary to assess the adequacy and validity of information and data supplied by the authorized account representative.
(a) Only Administrator-accredited independent verifiers may provide a verification report for an eligibility application or M&V report.
(b) Applications for accreditation must follow a procedure and form specified by the Administrator which includes a demonstration by the verifier that it meets the requirements in paragraph (c) of this section.
(c) Independent verifiers must meet each of the requirements in paragraphs (c)(1) through (6) of this section to be accredited.
(1) Independent verifiers must have the skills, experience, and resources (personnel and otherwise) to provide verification reports, including the following:
(i) Appropriate technical qualification (professional engineer or otherwise) to evaluate the eligible resource for which the independent verifier is seeking accreditation, which may include ANSI accreditation under ISO 14065 for GHG validation and verification bodies;
(ii) Appropriate auditing and accounting qualifications for financial and non-financial data monitoring, auditing, and quality assurance and quality control to evaluate the eligible resource for which the independent verifier is seeking accreditation;
(iii) Knowledge of the requirements of the Administrator's CO
(iv) Knowledge of the eligible resource categories for which the independent verifier is seeking accreditation, including relevant aspects of the design, operation, and related energy generation or electricity savings monitoring and reporting approaches for such eligible resources; and
(v) Capability to perform key verification activities, such as development of a verification report; performance of site visits; review and recalculation of reported data; review of data management systems; review of quantification methods used in accordance with an approved EM&V plan; preparation of a verification statement, list of findings, and verification report; and internal review of the verification findings and report.
(2) Independent verifiers must document, in the application for accreditation, the independent verifiers that will provide verification services, including lead verifiers, key personnel and any contractors or subcontractors (collectively, accredited independent verification team) and demonstrate that they meet the requirements of section § 62.16470(d)(1). Once accredited, only the accredited independent verification team identified in the accreditation application and accredited by the State may provide a verification report.
(3) An independent verifier must specify the eligible resource categories for which it is seeking accreditation, and an accredited independent verifier may only provide verification services related to an eligible resource category for which it is accredited.
(4) Prospective independent verifiers must meet the requirements of § 62.16475(d) through (f) and demonstrate that they have in place adequate systems and protocols to identify, disclose and avoid potential conflicts of interest.
(5) An accredited independent verifier must not be debarred, suspended, or proposed for debarment pursuant to the Government-wide Debarment and Suspension regulations, part 32 of this chapter, or the Debarment, Suspension and Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4.
(6) An accredited independent verifier must maintain, for its employees, and ensure the maintenance of, for any parties that it employs, professional liability insurance, as defined in 31 CFR 50.5(q), through an insurance provider that possesses a financial strength rating in the top four categories from either
(d) Requirements for maintenance of accreditation status, as follows:
(1) Accredited independent verifiers must meet the requirements of § 62.16475 when providing verification services for an authorized account representative; and
(2) The instances specified in § 62.16475(d) are cause for revocation of a verifier's accreditation.
(a) Accredited independent verifiers must not provide verification services for any eligible resource for which it has a conflict of interest (COI), which means:
(1) Accredited independent verifiers must have, or have had, no direct or indirect financial interest in, or other financial relationships with, an eligible resource, or any prospective eligible resource, for which they seek to provide a verification report;
(2) Accredited independent verifiers must have, or have had, no direct or indirect organizational or personal relationships with an eligible resource, that would impact their impartiality in assessing the validity and accuracy of the information in an eligibility application or M&V report;
(3) Accredited independent verifiers must have, or have had, no role in the development and implementation of an eligible resource for which an authorized account representative seeks issuance of ERCs, beyond the provision of verification services;
(4) Accredited independent verifiers must not be compensated, financially or otherwise, directly or indirectly, on the basis of the content of its verification report (including eligibility approval of an eligible resource, the quantified and verified MWh in an M&V report, ERC issuance, or the number of ERCs issued);
(5) Accredited independent verifiers must not own, buy, sell, or hold ERCs, or other financial derivatives related to ERCs, or have a financial relationship with other parties that own, buy, sell, or hold ERCs or other related financial derivatives;
(6) An accredited independent verifier must not be incapable of providing an impartial verification report for any other reason; and
(7) An accredited independent verifier must ensure that the subject of any verification report must not have the opportunity to review or influence any draft or final verification report before its submittal to the Administrator, and the accredited independent verifier must share any drafts of its reports with the Administrator at the same time as it shares them with the subject of the report.
(b) A contract with an eligible resource for the provision of verification services will not constitute a COI.
(c) Verification reports must include an attestation by the accredited independent verifier that it evaluated and disclosed to the Administrator any potential COI related to an eligible resource.
(d) Prior to engaging for the provision of verification services, an accredited independent verifier must demonstrate that it has no COI related to the eligible resource, as specified in paragraph (a) of this section. If a COI is identified for a person or persons within an accredited independent verifier for a specific subject or verification, in accordance with paragraphs (e) and (f) of this section, then an accredited independent verifier may propose to the Administrator steps that will be taken to eliminate the COI which include prohibiting the person or persons with the conflict from any involvement in the matter subject to the conflict, including verification services, access to information related to the verification services, access to any draft or final verification reports, any communications with the person(s) conducting the verification services. In no instance shall an accredited independent verifier engage in verification services for an eligible resource without the approval of the Administrator.
(e) Prior to engaging in verification services and writing a verification report, an accredited independent verifier must disclose to the Administrator all information necessary for the Administrator to evaluate a potential COI (including information concerning its ownership, past and current clients, related entities, as well as any other facts or circumstances that have the potential to create a COI).
(f) Accredited verifiers have an ongoing obligation to disclose to the Administrator any facts or circumstances that may give rise to a COI as defined in paragraph (a) of this section.
(g) The Administrator may reject a verification report from an accredited independent verifier, if the Administrator determines that the accredited independent verifier has a COI as defined in paragraph (a) of this section. If the Administrator rejects an accredited independent verifier report for such reasons, then the eligibility application or M&V report submittal shall be deemed incomplete and ERCs must not be issued pursuant to it.
(a) The Administrator may revoke the accreditation of an independent verifier at any time for cause, including for the reasons specified in paragraphs (a)(1) through (4) of this section.
(1) Failure to fully disclose any issues that may lead to a COI with respect to an eligible resource, or other related entity, in accordance with § 62.16475(d) through (f).
(2) The accredited independent verifier is no longer qualified to provide verification services.
(3) Negligence in the conduct of verification activities, or neglect of responsibilities pursuant to the requirements of §§ 62.16465, 62.16470, and 62.16475.
(4) Intentional misrepresentation of data in a verification report.
(b) [Reserved]
(a) Except as provided under § 62.16495, each affected EGU, and each eligible resource shall have one and only one designated representative, with regard to all matters under the CO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the affected EGU and must act in accordance with the certification statement in § 62.16500(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 62.16500:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the affected EGU in all matters pertaining to the CO
(ii) The owners and operators of the affected EGU shall be bound by any decision or order issued to the designated representative by the
(b) Except as provided under § 62.16495, each affected EGU may have one and only one alternate designated representative, who may act on behalf of the designated representative. The agreement by which the alternate designated representative is selected must include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the affected EGU and must act in accordance with the certification statement in § 62.16500(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 62.16500,
(i) The alternate designated representative must be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the affected EGU shall be bound by any decision or order issued to the alternate designated representative by the Administrator regarding any such affected EGU.
(c) Except in this section, §§ 62.16490 through 62.16510, and § 62.16570, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative.
(a) Except as provided under § 62.16510 concerning delegation of authority to make submissions, each submission under the CO
(b) The Administrator will accept or act on a submission made for an affected EGU only if the submission has been made, signed, and certified in accordance with paragraph (a) of this section and § 62.16510.
(a)
(b)
(c)
(2) Within 30 days after any change in the owners and operators of affected EGU, including the addition or removal of an owner or operator, the designated representative or any alternate designated representative must submit a revision to the certificate of representation under § 62.16500 amending the list of owners and operators to reflect the change.
(d)
(1) If the change is the addition of an affected EGU that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation must identify, in a format prescribed by the Administrator, the entity from whom the affected EGU was purchased or otherwise obtained (including name, address, telephone number, and facsimile transmission number (if any)), the date on which the affected EGU was purchased or otherwise obtained, and the date on which the affected EGU became located at the source.
(2) If the change is the removal of an affected EGU, then the certificate of representation must identify, in a format prescribed by the Administrator, the entity to which the affected EGU was sold or that otherwise obtained the affected EGU (including name, address, telephone number, and facsimile transmission number (if any)), the date on which the affected EGU was sold or otherwise obtained, and the date on which the affected EGU became no longer located at the source.
(a) A complete certificate of representation for a designated representative or an alternate designated representative must include the elements in paragraphs (a)(1) through (5) of this section in a format prescribed by the Administrator.
(1) Identification of the affected EGU for which the certificate of representation is submitted, including names, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, unit identification number and type,
(2) The name, address, email address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the affected EGU.
(4) The following certification statements by the designated representative and any alternate designated representative:
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the affected EGU”;
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, an affected EGU, or where a utility or industrial customer purchases power from an affected EGU under a life-of-the-unit, firm power contractual arrangement, I certify that: I have given a written notice of my selection as the `designated representative' or `alternate designated representative', as applicable, and of the agreement by which I was selected to each owner and operator of the affected EGU; and ERCs and proceeds of transactions involving CO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(a) Once a complete certificate of representation under § 62.16500 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 62.16500 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of ERC transfers.
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, email address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under § 62.16510(d) shall be deemed to be an electronic submission by me”; and
(ii) “Until this notice of delegation is superseded by another notice of delegation under § 62.16510(d), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under § 62.16510 is terminated.”
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall
(a)
(2) A compliance account will hold ERCs intended for surrender by a designated representative when demonstrating an affected EGUs compliance with a CO
(b)
(2) [Reserved]
(c)
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to ERCs held in the general account.
(B) The agreement by which the alternate authorized account representative is selected must include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account must include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, email address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the ERCs held in the general account;
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to ERCs held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities under the CO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2)
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to ERCs held in the general account in all matters pertaining to the CO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative; and
(C) Each person who has an ownership interest with respect to ERCs held in the general account shall be bound by any decision or order issued to the authorized account representative or alternate authorized account representative by the Administrator regarding the general account.
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account must be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to ERCs held in the general account. Each such submission must include the following certification statement by the authorized account representative or any alternate authorized account representative: “I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the ERCs held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information,
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest.
(i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the ERCs in the general account.
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the ERCs in the general account.
(iii)(A) In the event a person having an ownership interest with respect to ERCs in the general account is not included in the list of such persons in the application for a general account, such person shall be deemed to be subject to and bound by the application for a general account, the representation, actions, inactions, and submissions of the authorized account representative and any alternate authorized account representative of the account, and the decisions and orders of the Administrator, as if the person were included in such list.
(B) Within 30 days after any change in the persons having an ownership interest with respect to ERCs in the general account, including the addition or removal of a person, the authorized account representative or any alternate authorized account representative must submit a revision to the application for a general account amending the list of persons having an ownership interest with respect to the ERCs in the general account to include the change.
(4) Objections concerning authorized account representative and alternate authorized account representative.
(i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the CO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of ERCs transfers.
(5) Delegation by authorized account representative and alternate authorized account representative.
(i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, email address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under § 62.16515(c)(5)(iv) shall be deemed to be an electronic submission by me”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under § 62.16515(c)(5)(iv), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under § 62.16515(c)(5) is terminated.”
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the authorized account representative or alternate authorized account representative submitting such notice of delegation.
(6)
(ii) If a general account has no ERC transfers to or from the account for a 12-month period or longer and does not contain any ERCs, then the Administrator may notify the authorized account representative for the account that the account will be closed 30 days after the notice is sent. The account will be closed after the 30-day period unless, before the end of the 30-day period, the Administrator receives a correctly submitted ERC transfer under § 62.16525 to the account or a statement submitted by the authorized account representative or alternate authorized account representative demonstrating to the satisfaction of the Administrator good cause as to why the account should not be closed.
(d)
(e)
(f)
(g)
(1) Account holder names and information;
(2) Authorized account representative name and information;
(3) Qualifying eligible resource identification number, name, State, and contact information including street address, mailing address, phone number, and email;
(4) Category of qualifying eligible resource, according to the categories specified in § 62.16435(a)(4);
(5) The date the qualifying eligible resource commenced generation or saving of energy;
(6) Individual ERCs, each with a unique serial identifier that meets the requirements of paragraph (f) of this section;
(7) Records of ERC transfers among accounts, including the date of transfer and the accounts involved in the transfer;
(8) The date an ERC was surrendered for a compliance demonstration;
(9) Date an ERC was retired by the regulatory body; and
(10) Each eligibility application, EM&V plan, M&V report, and verification report associated with the issuance of each specific ERC, and each regulatory approval and any documentation that supports the issuance of each ERC by the Administrator.
(h)
(i)
(1)
(2)
(3)
(j)
(a) An authorized account representative seeking recordation of an ERC transfer must submit the transfer to the Administrator.
(b) An ERC transfer is correctly submitted if:
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each ERC that is in the transferor account and is to be transferred; and
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each ERC identified by serial number in the transfer.
(a) Except as provided in paragraph (b) of this section, within five business days of receiving an ERC transfer that is correctly submitted under § 62.16525,
(b) An ERC transfer to or from a compliance account that is submitted for recordation after the allowance transfer deadline for a compliance period and that includes any ERCs allocated for any compliance period before such allowance transfer deadline will not be recorded until after the Administrator completes the deductions from such compliance account under § 62.16535 for the compliance period immediately before such allowance transfer deadline.
(c) Where an ERC transfer is not correctly submitted under § 62.16525, the Administrator will not record such transfer.
(d) Within five business days of recordation of an ERC transfer under paragraphs (a) and (b) of the section, the Administrator will notify the authorized account representatives of both the transferor and transferee accounts.
(e) Within 10 business days of receipt of an ERC transfer that is not correctly submitted under § 62.16525, the Administrator will notify the authorized account representatives of both accounts subject to the transfer of:
(1) A decision not to record the transfer; and
(2) The reasons for such non-recordation.
For affected EGUs subject to the emission standards listed in Table 1 of this subpart, the owner or operator of an affected EGU must demonstrate compliance with its CO
(a)
(1) Were allocated for a year in such compliance period or a prior compliance period; and
(2) Are held in the affected EGU's compliance account as of the allowance transfer deadline for such compliance period.
(b)
(1) Until the amount of ERCs deducted and subsequently added to the total MWh generated by the affected EGU adjusts the affected EGU's CO
(2) If there are insufficient ERCs to complete the deductions in paragraph (b)(1) of this section, until no more ERCs available under paragraph (a) of this section remain in the compliance account.
(c)
(d)
(e)
(f)
(a) You must follow the requirements described in paragraphs (a)(1) through (8) of this section to monitor emissions and net energy output at your affected EGU.
(1) The owner of operator of an affected EGU required to meet an emission standard must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter, unless such a plan is already in place under another program that requires CO
(2) Each compliance period shall include only “valid operating hours” in the compliance period,
(i) “Valid data” (as defined in § 62.16570) are obtained for all of the parameters used to determine the hourly CO
(ii) The corresponding hourly net energy output value is also valid data (Note: for hours with no useful output, zero is considered to be a valid value).
(3) The owner or operator of an affected EGU must measure and report the hourly CO
(i) The owner or operator of an affected EGU must install, certify, operate, maintain, and calibrate a CO
(ii) For each “valid operating hour”, calculate the hourly CO
(iii) Next, multiply each hourly CO
(iv) The hourly CO
(v) Sum all of the hourly CO
(vi) For each continuous monitoring system used to determine the CO
(vii) The owner operator of an affected EGU must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO
(4) The owner or operator of an affected EGU that exclusively combusts liquid fuel and/or gaseous fuel may, as an alternative to complying with paragraph (a)(3) of this section, determine the hourly CO
(i) Implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly affected EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.
(ii) For each measured hourly heat input rate, use Equation G-4 in Appendix G to part 75 of this chapter to calculate the hourly CO
(iii) For each valid operating hour (as defined in paragraph (a)(2) of this section, determine the hourly CO
(iv) The hourly CO
(v) Sum all of the hourly CO
(vi) The owner or operator of an affected EGU may determine site-specific carbon-based F-factors (F
(5) The owner or operator of an affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output. The owner or operator must calculate net energy output according to paragraph (a)(5)(i) of this section.
(i) For each valid operating hour of a compliance period that was used in paragraph (a)(3) or (4) of this section to calculate the total CO
(A) Calculate P
(B) If applicable to your affected EGU (for example, for combined heat and power), then you must calculate (Pt)
(C) Sum all of the values of P
(ii) [Reserved]
(6) In accordance with § 60.13(g) of this chapter, if two or more affected EGUs implementing the continuous emissions monitoring provisions in paragraph (a)(2) of this section share a common exhaust gas stack and are subject to the same emission standard, then the owner or operator may monitor the hourly CO
(7) In accordance with § 60.13(g) of this chapter, if the exhaust gases from an affected EGU implementing the continuous emissions monitoring provisions in paragraph (a)(3)(i) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), then the hourly CO
(8) If two or more affected EGUs serve a common electric generator, then you must apportion the combined hourly net energy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU. Alternatively, if the affected EGUs are identical, then you may apportion the combined hourly net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU.
(b) [Reserved]
(a) An ERC may be banked for future use or transfer in a compliance account or a general account in accordance with paragraph (b) of this section.
(b) Any ERC that is held in a compliance account or a general account will remain in such account unless and until the ERC is deducted or transferred under §§ 62.16530, 62.16535, 62.16550, or 62.16565.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any ATCS account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
You must prepare and submit reports according to paragraphs (a) through (g) of this section, as applicable.
(a)(1) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter and you must include the following information, as applicable in the quarterly reports:
(i) The percentage of valid operating hours in each quarter described § 62.16540(a)(2) (
(ii) The hourly CO
(iii) The net electric output and the net energy output (P
(iv) The calculated CO
(v) The sum of the hourly net energy output values and the sum of the hourly CO
(vi) ERC replacement generation (if any), properly justified (see paragraph (a)(1)(viii) of this section);
(vii) The calculated CO
(viii) If the report covers the final quarter of a compliance period, then you must include the CO
(b) If any required monitoring system has not been provisionally certified by the applicable date on which emissions data reporting is required to begin under paragraph (a) of this section, then the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with § 75.4(j) of this chapter, § 75.37(b) of this chapter, or section 2.4 of appendix D to part 75 of this chapter (as applicable). Operating hours in which CO
(c) The designated representative of each affected EGU at the facility must make all submissions required under the CO
(d) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA.
(e) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart.
(f) If your affected EGU captures CO
(1) Report in accordance with the requirements of part 98, subpart RR, of this chapter, if injection occurs on-site; or
(2) Transfer the captured CO
(g) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected EGUs.
(a) The owner or operator of each affected EGU must maintain the records, as described in paragraph (a)(1) of this section, for at least 5 years following the date of each compliance period, occurrence, measurement, maintenance, corrective action, report, or record.
(1) Unless otherwise provided, the owner or operator of an affected EGU must maintain the following records on site for at least 2 years after the date of each compliance period, compliance true-up period, occurrence, measurement, maintenance, corrective action, report, or record, whichever is latest, according to § 60.7 of this chapter. The owner or operator of an affected EGU may maintain the records off site and electronically for the remaining year(s). This period may be extended for cause, at any time before the end of 5 years, in writing by the Administrator.
(i) The certificate of representation under § 62.16500 for the designated representative for each affected EGU and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents must be retained on site at the affected EGU beyond such 5-year period until such certificate of representation and documents are superseded because of the submission of a new certificate of representation under § 62.16500 changing the designated representative.
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, documents, data files, calculations and methods, other submissions and all records made or required under, or to demonstrate compliance with an affected EGU's emission standard under § 62.16420 and any other requirements of the CO
(iv) Data that are required to be recorded by part 75, subpart F, of this chapter.
(v) Data with respect to any ERCs generated by the affected EGU or used by the affected EGU in its compliance demonstration including the information in paragraphs (a)(1)(v)(A) and (B) of this section.
(A) All documents related to any ERCs used in a compliance demonstration, including each eligibility application, EM&V plan, M&V report, and independent verifier verification report associated with the issuance of each specific ERC, and each regulatory approval and any documentation that supports the issuance of each ERC by the Administrator.
(B) All records and reports relating to the surrender and retirement of ERCs for compliance with this regulation, including the date each individual ERC with a unique serial identification number was surrendered and/or retired.
(2) [Reserved]
(b) [Reserved]
(a) The Administrator may review and conduct independent audits concerning any submission under the CO
(b) The Administrator may deduct ERCs from or transfer ERCs to a compliance account, based on the information in a submission, as adjusted under paragraph (a) of this section, and record such deductions and transfers.
The terms used in this subpart have the meanings set forth in this section as follows:
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function or any other person who performs similar policy- or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
(1) Compliance Period 1 means the period of 3 calendar years from January 1, 2022 to December 31, 2024;
(2) Compliance Period 2 means the period of 3 calendar years from January 1, 2025 to December 31, 2027; and
(3) Compliance Period 3 means the period of 2 calendar years from January 1, 2028 to December 31, 2029.
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow;
(2) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(3) A CO
(4) An O
(1) In accordance with this subpart; and
(2) With regard to a period before the affected EGU or facility is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter.
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, ERC transfer in accordance with this subpart; and
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, ERC transfer in accordance with this subpart.
(1) The net electric or mechanical output from the affected facility, plus 100 percent of the useful thermal output measured relative to SATP conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the affected EGU (
(2) For combined heat and power facilities where at least 20.0 percent of the total net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total net energy output consists of useful thermal output on a 12-operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output (
(1) Any holder of any portion of the legal or equitable title in an affected EGU at the affected EGU or the affected EGU;
(2) Any holder of a leasehold interest in an affected EGU at the affected EGU or the affected EGU, provided that, unless expressly provided for in a leasehold agreement, “owner” shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly) on the revenues or income from such affected EGU; and
(3) Any purchaser of power from a affected EGU at the affected EGU or the affected EGU under a life-of-the-unit, firm power contractual arrangement.
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
The measurements, abbreviations, and acronyms used in this subpart are defined as follows:
42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, and 7651
(a)(1) This part shall govern appeals of any final decision of the Administrator under subparts MMM and NNN of part 62 of this chapter, part 72, 73, 74, 75, 76, or 77 of this chapter, subparts AA through II of part 96 of this chapter or State regulations approved under § 51.123(o)(1) or (2) of this chapter, subparts AAA through III of part 96 of this chapter or State regulations approved under § 51.124(o)(1) or (2) of this chapter, subparts AAAA through IIII of part 96 of this chapter or State regulations approved under § 51.123(aa)(1) or (2) of this chapter, part 97 of this chapter, or subpart RR of part 98 of this chapter; provided that matters listed in § 78.3(d) and preliminary, procedural, or intermediate decisions, such as draft Acid Rain permits, may not be appealed. All references in paragraph (b) of this section and in § 78.3 to subparts AA through II of part 96 of this chapter, subparts AAA through III of part 96 of this chapter, and subparts AAAA through IIII of part 96 of this chapter shall be read to include the comparable provisions in State regulations approved under § 51.123(o)(1) or (2) of this chapter, § 51.124(o)(1) or (2) of this chapter, and § 51.123(aa)(1) or (2) of this chapter, respectively.
(b) * * *
(18) Under subpart MMM of part 62 of this chapter,
(i) The decision on allocation of CO
(ii) The decision on allocation of CO
(iii) The decision on the transfer of CO
(iv) The decision on the deduction of CO
(v) The correction of an error in an ATCS account under § 62.16355 of this chapter.
(vi) The adjustment of information in a submission and the decision on the deduction and transfer of CO
(vii) The finalization of compliance period emissions data, including retroactive adjustment based on audit.
(19) Under subpart NNN of part 62 of this chapter,
(i) The decision on emission rate credit issuance, adjustment, and revocation under § 62.16435.
(ii) The decision on qualification status of eligible resources to receive emission rate credits under § 62.16460.
(iii) The decision on revocation of qualification status of an eligible resource under § 62.16440.
(iv) The decision on Adjustments for error or misstatement, suspension of ERC issuance under § 62.16450.
(v) The decision on accreditation of independent verifiers under § 62.16470.
(vi) The decision on revocation of accreditation status under § 62.16480.
(vii) The decision on the transfer of emission rate credits under § 62.16530 of this chapter.
(viii) The decision on the deduction of emission rate credits under § 62.16535 of this chapter.
(ix) The correction of an error in an ATCS account under § 62.16550 of this chapter.
(x) The adjustment of information in a submission and the decision on the deduction and transfer of emission rate credits based on the information as adjusted under § 62.16565 of this chapter.
(xi) The finalization of compliance period emissions data, including retroactive adjustment based on audit.
Category | Regulatory Information | |
Collection | Federal Register | |
sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
Publisher | Office of the Federal Register, National Archives and Records Administration |